UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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[X]☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| FOR THE FISCAL YEAR ENDED DECEMBER 31, 2020 | |
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2017
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[ ]☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| FOR THE TRANSITION PERIOD FROM ___________ TO __________ | |
or
FOR THE TRANSITION PERIOD FROM ___________ TO __________
COMMISSION FILE NUMBER 001-03551
EQT CORPORATION
(Exact name of registrant as specified in its charter)
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PENNSYLVANIA
Pennsylvania | | 25-0464690 |
| (State or other jurisdiction of incorporation or organization)
| 25-0464690
| (IRS Employer Identification No.)
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| 625 Liberty Avenue, Suite 1700 | | |
| Pittsburgh, Pennsylvania | | 15222 |
| (Address of principal executive offices) | 15222
| (Zip Code) |
Registrant’s(412) 553-5700
(Registrant's telephone number, including area code: (412) 553-5700code)
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | | Trading symbol(s) | | Name of each exchange on which registered |
| Common Stock, no par value | | EQT | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X ☒ No ___☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ___☐ No X☒
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X ☒ No ___☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X ☒ No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ]☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large"large accelerated filer,” “accelerated" "accelerated filer,” “smaller" "smaller reporting company”company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
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| Large accelerated filer | ☒ | Accelerated filer | ☐ |
| Non-accelerated filer | ☐ | Smaller reporting company | ☐ |
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Large accelerated filer X | Accelerated filer ___ |
Non-accelerated filer ___ (Do not check if a smaller reporting company) | Smaller reporting company ___ |
| Emerging growth company ___ | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ___☐ No X☒
The aggregate market value of votingcommon stock held by non-affiliates of the registrant as of June 30, 2017: $10.12020: $3.0 billion
The numberAs of February 12, 2021, 278,854,465 shares (in thousands) of common stock, outstanding asno par value, of January 31, 2018: 264,473the registrant were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The Company’sEQT Corporation's definitive proxy statement relating to the 2018its 2021 annual meeting of shareholders will be filed with the Securities and Exchange Commission within 120 days after the close of the Company’sEQT Corporation's fiscal year ended December 31, 20172020 and is incorporated by reference in Part III to the extent described therein.
TABLE OF CONTENTS
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| PART I |
PART I |
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| Business1. | | |
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| Properties2. | | |
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| | PART II |
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PART II |
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Item 5 | | |
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| Management’s | |
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| PART III |
PART III |
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| | PART IV |
PART IV |
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Item 15 | | |
| Signatures | | |
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Glossary of Commonly Used Terms, Abbreviations and Measurements
Unless the context otherwise indicates, all references in this report to "EQT," the "Company," "we," "us," or "our" are to EQT Corporation and its subsidiaries, collectively.
Commonly Used Terms
AFUDC (Allowance for Funds Used During Construction) – carrying costs for the construction of certain long-term regulated assets are capitalized and amortized over the related assets’ estimated useful lives. The capitalized amount for construction of regulated assets includes interest cost and a designated cost of equity for financing the construction of these regulated assets.
Appalachian Basin – the area of the United States composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains.
basis – when referring to commodity pricing, the difference between the futures price for a commodity and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location, transportation capacity availability and contract pricing.
British thermal unit – a measure of the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit.
collar – a financial arrangement that effectively establishes a price range for the underlying commodity. The producer bears the risk and benefit of fluctuation between the minimum (floor) price and the maximum (ceiling) price.
continuous accumulations – natural gas and oil resources that are pervasive throughout large areas, have ill-defined boundaries and typically lack, or are unaffected by, hydrocarbon-water contacts near the base of the accumulation.
conventional reservoir – an area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps utilizing conventional recovery methods.
development well – a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
exploratory well – a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.
extension well – a well drilled to extend the limits of a known reservoir.
feet of pay – footage penetrated by the drill bit into the target formation.
gas – all references to “gas”"gas" in this report refer to natural gas.
gross – “gross”"gross" natural gas and oil wells or “gross”"gross" acres equal the total number of wells or acres in which the Company haswe have a working interest.
hedging – the use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility.
horizontal drilling – drilling that ultimately is horizontal or near horizontal to increase the length of the well bore penetrating the target formation.
horizontal wells – wells that are drilled horizontal or near horizontal to increase the length of the well bore penetrating the target formation.
multiple completion well – a well equipped to produce oil and/or gas separately from more than one reservoir. Such wells contain multiple strings of tubing or other equipment that permit production from the various completions to be measured and accounted for separately.
Glossary of Commonly Used Terms, Abbreviations and Measurements
natural gas liquids (NGLs) – those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation adsorption or other methods in gas processing plants. Natural gas liquids include primarily ethane, propane, butane and iso-butane.isobutane.
net – “net”"net" natural gas and oil wells or “net”"net" acres are determined by adding the fractional ownership working interests the Company haswe have in gross wells or acres.
net revenue interest – the interest retained by the Companyus in the revenues from a well or property after giving effect to all third-party interests (equal to 100% minus all royalties on a well or property).
option – a contract that gives the buyer the right, but not the obligation, to buy or sell a specified quantity of a commodity or other instrument at a specific price within a specified period of time.
physical basis sales contracts – contracts for the sale of natural gas with physical delivery at a specified location and priced at NYMEX natural gas prices, plus or minus a fixed differential.
play – a proven geological formation that contains commercial amounts of hydrocarbons.
productive well – a well that is producing oil or gas or that is capable of production.
proved reserves – quantities of oil, natural gas, NGLs and NGLsoil, which, by analysis of geologicalgeoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
proved developed reserves – proved reserves whichthat can be expected to be recovered through existing wells with existing equipment and operating methods.
proved undeveloped reserves (PUDs) – proved reserves that can be estimated with reasonable certainty to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
reliable technology – a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonable certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
reservoir – a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
royalty interest – the land owner’s share of oil or gas production, typically 1/8.
service well – a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include, among other things, gas injection, water injection and salt-water disposal.
stratographic stratigraphictest well– a hole drilled for the sole purpose of gaining structural or stratigraphic information to aid in exploring for oil and gas.
well pad – an area of land that has been cleared and leveled to enable a drilling effort, geologically directed,rig to obtain information pertaining tooperate in the exploration and development of a specific geological condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production.
throughput – the volume of natural gas transported or passing through a pipeline, plant, terminal, or other facility during a particular period.oil well.
working gas – the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility.
working interest – an interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.
Glossary of Commonly Used Terms, Abbreviations and Measurements
Abbreviations
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CFTC – Commodity Futures Trading Commission |
EPA – U.S. Environmental Protection Agency |
ESG – Environmental, Social and Governance initiatives |
FERC – Federal Energy Regulatory Commission |
GAAP – U.S. Generally Accepted Accounting Principles |
IRS – Internal Revenue Service |
NYMEX – New York Mercantile Exchange |
OTC – over the counter |
SEC – U.S. Securities and Exchange Commission |
ASC – Accounting Standards Codification
CFTC – Commodity Futures Trading CommissionEPA – U.S. Environmental Protection Agency
FASB – Financial Accounting Standards Board
FERC – Federal Energy Regulatory Commission
GAAP – U.S. Generally Accepted Accounting Principles
IPO – initial public offering
IRS – Internal Revenue Service
NYMEX – New York Mercantile Exchange
OTC – over the counter
SEC – Securities and Exchange Commission
Measurements
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Bbl = barrel |
Bcf = billion cubic feet |
Bcfe = billion cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas |
Btu = one British thermal unit |
Dth = dekatherm or million British thermal units |
Mbbl = thousand barrels |
Mcf = thousand cubic feet |
Mcfe = thousand cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas |
MMbbl = million barrels |
MMBtu = million British thermal units |
MMcf = million cubic feet |
MMcfe = million cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas |
MMDth = million dekatherm |
Tcfe = trillion cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas |
BBtu = billion British thermal units
Bcf = billion cubic feetCAUTIONARY STATEMENTS
Bcfe = billion cubic feet of natural gas
equivalents, with one barrel of NGLs and crude oil
being equivalent to 6,000 cubic feet of natural gas
Btu = one British thermal unit
Dth = million British thermal units
Mbbl = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of natural gas
equivalents, with one barrel of NGLs and crude oil
being equivalent to 6,000 cubic feet of natural gas
MMBtu = million British thermal units
MMcf = million cubic feet
MMcfe = million cubic feet of natural gas
equivalents, with one barrel of NGLs and crude oil
being equivalent to 6,000 cubic feet of natural gas
MMgal = million gallons
TBtu = trillion British thermal units
Tcfe = trillion cubic feet of natural gas
equivalents, with one barrel of NGLs and crude oil
being equivalent to 6,000 cubic feet of natural gas
Cautionary Statements
Disclosures in thisThis Annual Report on Form 10-K containcontains certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and are usually identified by the use of words such as “anticipate,” “estimate,” “could,” “would,” “will,” “may,” “forecast,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe”"anticipate," "estimate," "could," "would," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe" and other words of similar meaning, or the negative thereof, in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include the matters discussed in the section captioned “Strategy”sections "Strategy" and "Outlook" in Item 1, “Business,” the sections captioned “Outlook” and “Impairment1., "Business," section "Impairment of Oil and Gas Properties and Goodwill”Properties" in Item 7, “Management’s7., "Management's Discussion and Analysis of Financial Condition and Results of Operations,”" and the expectations of our plans, strategies, objectives and growth and anticipated financial and operational performance, of the Company and its subsidiaries, including guidance regarding the Company’sour strategy to develop its Marcellus, Utica, Upper Devonian and otherour reserves; drilling plans and programs (including the number, type, feet of pay, average lateral lengths and location of wells to be drilled and the availability of capital to complete thesesuch plans and programs); the projected scope and timing of our combo-development projects; estimated reserves, including potential future downward adjustments of reserves and reserve life; total resource potential and drilling inventory duration; projected production and sales volumes and growth rates (including liquids volumes)production and sales volumes and growth rates; the Company's ability to maximize recoveries per acre; gathering and transmission volumes; the weighted average contract life of firm gathering, transmission and storage contracts; infrastructure programs (including the timing, cost and capacity of the gathering and transmission expansion projects)rates); the cost, capacity, timing of regulatory approvals and anticipated in-service date of the Mountain Valley Pipeline (MVP) project; the ultimate terms, partners and structure of Mountain Valley Pipeline, LLC; technology (including drilling and completion techniques); monetization transactions, including asset sales, joint ventures or other transactions involving the Company’s assets; acquisition transactions; whether the Company will sell its Ohio midstream assets to EQT Midstream Partners, LP and the timing of such transaction or transactions; the Company’s ability to achieve the anticipated synergies, operational efficiencies and returns from its acquisition of Rice Energy Inc.; the timing of the Company's announcement of a decision for addressing its sum-of-the-parts discount; natural gas prices, changes in basis and the impact of commodity prices on the Company'sour business; reserves, including potential future downward adjustments;impacts to our business and operations resulting from COVID-19 or a similar pandemic; potential future impairments of the Company'sour assets; projectedour ability to reduce our drilling and completions costs, other costs and expenses and capital expenditures, and capital contributions;the timing of achieving any such reductions; infrastructure programs; the cost, capacity and timing of obtaining regulatory approvals; our ability to successfully implement and execute our operational, organizational, technological and ESG initiatives, and achieve the anticipated benefits of such initiatives; projected reductions of our gathering and compression rates resulting from our consolidated gathering agreement with EQM Midstream Partners, LP, and the anticipated cost savings and other strategic benefits associated with the execution of such agreement; monetization transactions, including asset sales, joint ventures or other transactions involving our assets, and our planned use of the proceeds from any such monetization transactions; potential acquisitions or other strategic transactions, the timing thereof and our ability to achieve the intended operational, financial and strategic benefits from any such transactions; the timing and structure of any dispositions of our remaining retained shares of Equitrans Midstream Corporation's (Equitrans Midstream's) common stock, and the planned use of the proceeds from any such dispositions; the amount and timing of any repayments, redemptions or repurchases underof our common stock, outstanding debt securities or other debt instruments; our ability to reduce our debt and the Company’s share repurchase authorization;timing of such reductions, if any; projected dividend amounts and rates; projected cash flows and free cash flow; projected capital expenditures; liquidity and financing requirements, including funding sources and availability; our ability to maintain or improve our credit ratings, leverage levels and financial profile; our hedging strategy; the effects of litigation, government regulation and litigation;tax position; and the expected impact of the Tax Cuts and Jobs Act of 2017; andchanges to tax position.laws. The forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company hasWe have based these forward-looking statements on current expectations and assumptions about future events.events, taking into account all information currently known by us. While the Company considerswe consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond the Company’sour control. The risks and uncertainties that may affect the operations, performance and results of the Company’sour business and forward-looking statements include, but are not limited to, those set forth underin Item 1A, “Risk Factors,” and elsewhere1A., "Risk Factors" in this Annual Report on Form 10-K.10-K, and other documents we file from time to time with the SEC.
Any forward-looking statement speaks only as of the date on which such statement is made, and the Company doeswe do not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.otherwise, except as required by law.
Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and our development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.
In reviewing any agreements incorporated by reference in or filed with this Annual Report on Form 10-K, please remember such agreements are included to provide information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about the Company.us. The agreements may contain representations and warranties by the Company,us, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to such agreements should those statements prove to be inaccurate. The representations and warranties were intended to be relied upon solely by the applicable party to such agreement and were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments. Accordingly, thesesuch representations and warranties alone may not describe theour actual state of affairs or the affairs of the Company or itsour affiliates as of the date they were made or at any other time.time and should not be relied upon as statements of fact.
PART I
Item 1.Business
General
EQT Corporation (EQT or the Company) conducts its business through five business segments: EQT Production, EQM Gathering, EQM Transmission, RMP Gathering and RMP Water. EQT Production is the leadingWe are a natural gas producerproduction company with operations focused in the United States, basedMarcellus and Utica Shales of the Appalachian Basin. Based on average daily sales volumes, with 21.4we are the largest producer of natural gas in the United States. As of December 31, 2020, we had 19.8 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 4.01.8 million gross acres, including approximately 1.11.5 million gross acres in the Marcellus play, manyplay.
Strategy
We are committed to responsibly developing our world-class asset base and being the operator of choice for all stakeholders. By promoting a culture that prioritizes operational efficiency, technology and sustainability, we seek to continuously improve the way we produce environmentally responsible, reliable low-cost energy. We believe that the scale and contiguity of our acreage position differentiates us from our Appalachian Basin peers and that our evolution into a modern, digitally-enabled exploration and production business enhances our strategic advantage.
Our operational strategy focuses on the successful execution of combo-development projects. Combo-development refers to the development of several multi-well pads in tandem. Combo-development generates value across all levels of the reserves development process by maximizing operational and capital efficiencies. In the drilling stage, rigs spend more time drilling and less time transitioning to new sites. Advanced planning, a prerequisite to pursuing combo-development, facilitates the delivery of bulk hydraulic fracturing sand and piped fresh water (as opposed to truck-transported water), the ability to continuously meet completions supply needs and the use of environmentally friendly technologies. Operational efficiencies realized from combo-development are passed on to our service providers, which reduces overall contract rates.
The benefits of combo-development extend beyond financial gains to include environmental and social interests. We have developed an integrated ESG program that interplays with our combo-development-driven operational strategy. Core tenets of our ESG program include investing in technology and human capital; improving data collection, analysis and reporting; and engaging with stakeholders to understand, and align our actions with, their needs and expectations. Combo-development, when compared to similar production from non-combo-development operations, translates into fewer trucks on the road, decreased fuel usage, shorter periods of noise pollution, fewer areas impacted by midstream pipeline construction and shortened duration of site operations, all of which have associated deep Uticafosters a greater focus on safety and environmental protection.
Combo-development projects require significant advanced planning, including the establishment of a large, contiguous leasehold position; the advanced acquisition of regulatory permits and sourcing of fracturing sand and water; the timely verification of midstream connectivity; and the ability to quickly respond to internal and external stimuli. Without a modern, digitally-connected operating model or Upper Devonian drilling rights,an acreage position that enables operations of this scale, combo-development would not be possible.
We believe that our proprietary digital work environment in conjunction with the size and approximately 0.1contiguity of our asset base uniquely position us to execute on a multi-year inventory of combo-development projects in our core acreage position. Our operational strategy employs this differentiation to advance our mission of being the operator of choice for all stakeholders. We believe that combo-development projects are key to delivering sustainably low well costs and higher returns on invested capital and that our long-term transformative plan has been designed to create value by leveraging our strategic advantage, both operational and environmental, over our peers.
2020 Highlights
•Achieved 2020 sales volumes of 1,498 Bcfe or average daily sales volumes of 4.1 Bcfe per day; received an average realized price of $2.37 per Mcfe.
•Reduced 2020 capital expenditures by $694 million, gross acresor 39.1%, compared to 2019, while delivering flat sales volumes.
•Increased total proved reserves by 2.3 Tcfe or 13% in the Ohio Utica as2020 compared to 2019.
•Decreased total debt by $368 million and addressed near-term maturities, improving our financial position.
•Executed a new gas gathering agreement and exchanged half of December 31, 2017. EQM Gathering and EQM Transmission provideour equity stake in Equitrans Midstream, substantially reducing our future gathering transmission and storage services for the Company’s produced gas, as well as for independent third parties acrossfee structure.
•Acquired strategic assets from Chevron U.S.A. Inc. located in the Appalachian Basin through EQT Midstream Partners, LP (EQM) (NYSE: EQM), a publicly traded limited partnership formed by EQTfor an aggregate purchase price of $735 million (Chevron Acquisition).
•Divested certain non-strategic assets for an aggregate purchase price of $125 million.
•Executed long-term contract to own, operate, acquire and develop midstream assetsuse electric hydraulic fracturing services in the Appalachian Basin. RMP Gathering provides natural gas gathering services to the Companyour completions operations, promoting our ESG initiatives.
•Received approximately $440 million in the dry gas core of the Marcellus Shale in southwestern Pennsylvania,through Rice Midstream Partners LP (RMP) (NYSE: RMP). RMP Water provides water services that support well completion activities and collects and recycles or disposes of flowback and produced water for the Company and third parties in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio also through RMP.federal income tax refunds, including interest.
On November 13, 2017, the Company completed its acquisition of Rice Energy Inc. (Rice) pursuant to the Agreement and Plan of Merger, dated as of June 19, 2017 (as amended, the Merger Agreement), by and among the Company, Rice and a wholly owned indirect subsidiary of the Company (Merger Sub). Pursuant to the terms of the Merger Agreement, on November 13, 2017, Merger Sub merged with and into Rice (the Rice Merger) with Rice continuing as the surviving corporation in the Rice Merger. Immediately after the effective time of the Rice Merger (the Effective Time), Rice was merged with and into another wholly owned indirect subsidiary of the Company.Outlook
The Company acquired a total of approximately 270,000 net acres through the Rice Merger, which includes approximately 205,000 net Marcellus acres, as well as approximately 65,000 net Utica acres in Ohio. The Company also acquired Upper Devonian and Utica drilling rights held in Pennsylvania. In addition, the Company acquired a 28% limited partner interest, all of the incentive distribution rights (IDRs) and the entire non-economic general partner interest in RMP, as well as certain retained gathering assets located in Belmont and Monroe Counties, Ohio (the Rice retained gathering assets). See Note 2 to the Consolidated Financial Statements for additional information related to the Rice Merger.
In 2015, the Company formed EQT GP Holdings, LP (EQGP) (NYSE: EQGP), a Delaware limited partnership,2021, we expect to own the Company's partnership interestsspend approximately $1.1 to $1.2 billion in EQM. As of December 31, 2017, the Company owned the entire non-economic general partner interesttotal capital expenditures, excluding amounts attributable to noncontrolling interests. We expect to fund planned capital expenditures with cash generated from operations, allocated as follows: approximately $800 to $850 million to fund reserve development, approximately $125 to $140 million to fund land and a 90.1% limited partner interest,lease acquisitions, approximately $130 to $155 million to fund other production infrastructure and approximately $45 to $55 million applied towards capitalized overhead. Reserve development capital expenditures will be spent across our three primary operating areas, with approximately 65% spent in EQGP. As of December 31, 2017, EQGP's only cash-generating assets were the following EQM partnership interests: a 26.6% limited partner interestPennsylvania Marcellus, approximately 30% spent in EQM; a 1.8% general partner interestWest Virginia Marcellus, and approximately 5% spent in EQM; and all of EQM's IDRs. The CompanyOhio Utica. Our 2021 capital expenditure program is the ultimate parent company of EQGP, EQM and RMP.
Dueexpected to the Company's ownership and control of EQGP, EQM and RMP, the results of EQGP, EQM and RMP are consolidated in the Company’s financial statements. The Company records the noncontrolling interests of the public limited partners of EQGP, EQM and RMP in its financial statements.
Key Events in 2017
With the completion of the Rice Merger, the Company became the leading natural gas producer in the United States based on average daily sales volumes. Other significant events in 2017 for EQT included:
EQT achieved record annual productiondeliver sales volumes including a 17%of 1,620 Bcfe to 1,700 Bcfe, an increase in totalof 120-200 Bcfe when compared to 2020 sales volumes and a 17% increase in Marcellus sales volumes. Average realized priceprimarily driven by increased 23% to $3.04 per Mcfe in 2017 from $2.47 per Mcfe in 2016.
On February 1, 2017, the Company acquired approximately 14,000 net Marcellus acres located in Marion, Monongalia and Wetzel Counties, West Virginia from a third party for $132.9 million.
On February 27, 2017, the Company acquired approximately 85,000 net Marcellus acres, including drilling rights on approximately 44,000 net Utica acres, from Stone Energy Corporation for $523.5 million. The acquired acres are primarily located in Wetzel, Marshall, Tyler and Marion Counties, West Virginia. The acquired assets also included 174 operated Marcellus wells and 20 miles of gathering pipeline.
On June 30, 2017, the Company acquired approximately 11,000 net Marcellus acres, and the associated Utica drilling rights, from a third party for $83.7 million. The acquired acres are primarily located in Allegheny, Washington and Westmoreland Counties, Pennsylvania.
On October 4, 2017, the Company completed the public offering of $3.0 billion principal amount of notes. The Company used the net proceedsproduction from the saleChevron Acquisition.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of, the notes to fund a portion of the cash consideration for the Rice Merger, to pay expenses related to the Rice Merger and related transactions, to redeem $700 million aggregate principal amount of Company indebtedness due in 2018 and for other general corporate purposes.
On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for Mountain Valley Pipeline, LLC (MVP Joint Venture).
Business Segments
Prior to the Rice Merger, the Company reported its results of operations through three business segments: EQT Production, EQT Gathering and EQT Transmission. These reporting segments reflected the Company's lines of business and were reported in the same manner in which the Company evaluated its operating performance through September 30, 2017. Following the Rice Merger, the Company adjusted its internal reporting structure to incorporate the newly acquired assets. The Company now conducts its business through five business segments: EQT Production, EQM Gathering (formerly known as EQT Gathering), EQM Transmission (formerly known as EQT Transmission), RMP Gathering and RMP Water. The EQT Production segment incorporates the Company’s production activities, including those acquired in the Rice Merger, the Company's marketing operations, and certain gathering operations primarily supporting the Company's production activities, including the Rice retained gathering assets. The EQM Gathering segment and the EQM Transmission segment include all of the Company's assets and operations that are owned by EQM; therefore, the financial and operational disclosures related to EQM Gathering and EQM Transmission in this Annual Report on Form 10-K are the same as EQM’s disclosures in its Annual Report on Form 10-K for the year ended December 31, 2017. The RMP Gathering segment contains the Company's gathering assets that are owned by RMP. The RMP Water segment contains the Company's water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities owned by RMP. Following the Rice Merger, the financial and operational disclosures related to RMP Gathering and RMP Water will be the same as RMP’s successor disclosures in its Annual Report on Form 10-K for the year ended December 31, 2017.
The following illustration depicts EQT’s consolidated acreage position along with its gathering and transmission systems:
EQT Production Business Segment
EQT Production holds 21.4 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 4.0 million gross acres, including approximately 1.1 million gross acresoil. Due to the volatility of commodity prices, we are unable to predict future potential movements in the Marcellus play, manymarket prices for natural gas, NGLs and oil at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations. Changes in natural gas, NGLs and oil prices could affect, among other things, our development plans, which would increase or decrease the pace of the development and the level of our reserves, as well as our revenues, earnings or liquidity. Lower prices and changes in our development plans could also include associated deep Utica or Upper Devonian drilling rights, and approximately 0.1 million gross acresresult in non-cash impairments in the Ohio Utica, asbook value of December 31, 2017. EQT believes that it is a technology leader in horizontal drillingour oil and completions in the Appalachian Basingas properties or downward adjustments to our estimated proved reserves. Any such impairments or downward adjustments to our estimated reserves could potentially be material to us.
See "Impairment of Oil and continues to improve its operations through the use of new technology. EQT Production’s strategy is to maximize shareholder value by maintaining an industry leading cost structure to profitably develop its reserves. EQT’s proved reserves increased 59% in 2017, primarily as a result of acquisitions. The Company’s Marcellus assets constituted approximately 16.9 Tcfe of the Company's total proved reserves as of December 31, 2017.
As of December 31, 2017, the Company’s proved reserves were as follows:
|
| | | | | | | | | | | | | | | |
| (Bcfe) | | Marcellus | | Upper Devonian | | Ohio Utica | |
Other | | Total |
| Proved Developed | | 8,092 |
| | 683 |
| | 757 |
| | 1,767 |
| | 11,299 |
|
| Proved Undeveloped | | 8,805 |
| | 293 |
| | 1,049 |
| | — |
| | 10,147 |
|
| Total Proved Reserves | | 16,897 |
| | 976 |
| | 1,806 |
| | 1,767 |
| | 21,446 |
|
The Company’s natural gas wells are generally low-risk, having a long reserve life with relatively low developmentGas Properties" and production costs on a per unit basis. Assuming that future annual production from these reserves is consistent with 2018 production guidance, the remaining reserve life of the Company’s total proved reserves, as calculated by dividing total proved reserves by 2018 produced volumes guidance, is 14 years.
The Company invested approximately $1,385 million on well development during 2017, with total production sales volumes of 887.5 Bcfe, an increase of 17% over the previous year. EQT Production expects to spend approximately $2.2 billion for well development (primarily drilling"Critical Accounting Policies and completion) in 2018, which is expected to support the drilling of approximately 195 gross wells, including 134 Marcellus wells, 16 Upper Devonian wells and 45 Ohio Utica wells. The Company also intends to spend approximately $0.2 billion for acreage fill-ins, bolt-on leasing, and other items. During the past three years, the Company’s number of wells drilled (spud) and related capital expenditures for well development were:
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| Gross wells spud: | | | | | | |
| Horizontal Marcellus* | | 193 |
| | 130 |
| | 157 |
|
| Ohio Utica | | 7 |
| | — |
| | — |
|
| Other | | 1 |
| | 5 |
| | 4 |
|
| Total | | 201 |
| | 135 |
| | 161 |
|
| | | | | | | |
| Capital expenditures for well development (in millions): |
| Horizontal Marcellus* | | $ | 1,295 |
| | $ | 686 |
| | $ | 1,527 |
|
| Ohio Utica | | 31 |
| | — |
| | — |
|
| Other | | 59 |
| | 97 |
| | 143 |
|
| Total | | $ | 1,385 |
| | $ | 783 |
| | $ | 1,670 |
|
* Includes Upper Devonian formations.
The EQT Production segment also includes the following gathering assets which are not owned by EQM or RMP:
approximately 152 miles of high pressure gathering lines and 4 compressor stations in Belmont and Monroe County, Ohio as of December 31, 2017;
Strike Force Midstream Holdings LLC's (Strike Force Holdings) 75% membership interest in Strike Force Midstream LLC (Strike Force Midstream), which owns approximately 67 miles of high pressure gathering lines and 2 compressor stations in Belmont and Monroe County, Ohio, as of December 31, 2017; and
approximately 6,600 miles of gathering lines that primarily support the Company's and third party production operations in non-core areas of declining production.
Third party revenues for these gathering services areEstimates" included in pipeline and net marketing services revenues for the EQT Production segment and were approximately $30.8 million for the year ended December 31, 2017, inclusive of third party revenues during the period of November 13, 2017 through December 31, 2017 for EQT Production including the Rice retained gathering assets.
The Company optimizes its transportation and processing assets to sell natural gas and NGLs to marketers, utilities and industrial customers within its operational footprint and in markets available through the Company's current transportation portfolio. The Company provides marketing services for the benefit of EQT Production and third parties and manages approximately 2.4 Bcf per day of firm third party contractual pipeline takeaway capacity and 685 MMcf per day of firm third party processing capacity. The Company has also committed to 1.29 Bcf per day of firm capacity on the MVP (defined under EQM Transmission) and approximately 0.3 Bcf per day of additional third party contractual takeaway capacity expected to come online in future periods.
EQM Gathering Business Segment
As of December 31, 2017, EQM Gathering included approximately 300 miles of high pressure gathering lines with approximately 2.3 Bcf per day of total firm contracted gathering capacity, compression of approximately 189,000 horsepower and multiple interconnect points with EQM Transmission's transmission and storage system. EQM Gathering's system also included approximately 1,500 miles of FERC-regulated low pressure gathering lines.
In the ordinary course of its business, EQM Gathering pursues gathering expansion projects for affiliates and third party producers. EQM Gathering invested approximately $197 million on gathering projects in 2017 that added 475 MMcf per day of firm gathering capacity in southwestern Pennsylvania. This included the final phase of the header pipeline for Range Resources Corporation (Range Resources)Item 7., which was placed in-service during the second quarter of 2017. The system now provides total firm gathering capacity of 600 MMcf per day at a total project cost of approximately $240 million. This and other expansion projects, primarily for affiliates, supported increased gathered volumes of 11% and gathering revenues of 14% in 2017. In 2018, EQM Gathering estimates capital expenditures of approximately $300 million on gathering expansion projects, primarily driven by affiliate wellhead and header projects in Pennsylvania and West Virginia, including the Hammerhead project, a 1.2 Bcf per day gathering header connecting Pennsylvania and West Virginia production to the MVP.
EQM Transmission Business Segment
As of December 31, 2017, EQM Transmission's transmission and storage system included an approximately 950-mile FERC-regulated interstate pipeline that connects to seven interstate pipelines and local distribution companies. The transmission system is supported by 18 associated natural gas storage reservoirs with approximately 645 MMcf per day of peak withdrawal capacity, 43 Bcf of working gas capacity and 41 compressor units, with total throughput capacity of approximately 4.4 Bcf per day and compression of approximately 120,000 horsepower as of December 31, 2017.
In the ordinary course of its business, EQM Transmission pursues transmission projects aimed at profitably increasing system capacity. EQM Transmission invested approximately $111 million on transmission and storage system infrastructure in 2017. Revenues in 2017 increased by approximately $41 million or 12% compared to 2016. In 2018, EQM Transmission will focus on the following transmission projects:
Mountain Valley Pipeline (MVP). The MVP Joint Venture is a joint venture with affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc., WGL Holdings, Inc. and RGC Resources, Inc. EQM is the operator of the MVP and owned a 45.5% interest in the MVP Joint Venture as of December 31, 2017. The 42 inch diameter MVP has a targeted capacity of 2.0 Bcf per day and is estimated to span 300 miles extending from EQM Transmission's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia providing access to the growing Southeast demand markets. As currently designed, the MVP is estimated to cost a total of approximately $3.5 billion, excluding AFUDC, with EQM funding its proportionate share through capital contributions made to the joint venture. In 2018, EQM expects to provide capital contributions of $1.0 billion to $1.2 billion to the MVP Joint Venture. The MVP Joint Venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms, including a 1.29 Bcf per day firm capacity commitment by EQT, and is currently in negotiation with additional shippers who have expressed interest in the MVP project. On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for the project. In January 2018, the MVP Joint Venture received multiple limited notices to proceed from the FERC to begin construction
activities on certain facilities. The MVP Joint Venture plans to commence construction in the first quarter of 2018. The pipeline is targeted to be placed in-service during the fourth quarter of 2018.
Transmission Expansion. In 2018, EQM Transmission estimates capital expenditures of approximately $100 million for other transmission expansion projects, primarily attributable to the Equitrans Expansion project. The Equitrans Expansion project is designed to provide north-to-south capacity on the mainline Equitrans system for deliveries to the MVP.
RMP Gathering Business Segment
As of December 31, 2017, RMP Gathering included an approximately 178 mile high pressure dry gas gathering system with approximately 5.1 TBtu per day of gathering capacity and compression capacity of approximately 85,000 horsepower that services the Company and third parties in Washington and Greene Counties, Pennsylvania, with connections to five interstate pipelines.
RMP Water Business Segment
RMP Water's assets include water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities used to support well completion activities and to collect and recycle or dispose of flowback and produced water for the Company and third parties in Washington and Greene Counties, Pennsylvania, and Belmont County, Ohio. As of December 31, 2017, RMP Water's Pennsylvania assets provided access to 29.4 MMgal per day of fresh water from the Monongahela River and several other regional water sources, and RMP Water's Ohio assets provided access to 14.0 MMgal per day of fresh water from the Ohio River and several other regional water sources.
Strategy
EQT’s strategy is to maximize shareholder value by profitably and safely developing its undeveloped reserves while maintaining an industry leading cost structure and effectively and efficiently utilizing EQM's and RMP's extensive midstream assets that are uniquely positioned across the Marcellus, Upper Devonian and Utica Shales.
Following the Rice Merger, the Company has significant acreage scale in the core of the Marcellus which will allow EQT to drill considerably longer laterals, realize operational efficiencies and improve overall returns. EQT believes that it is a technology leader in horizontal drilling and completion in the Appalachian Basin and continues to improve its operations through the use of new technology. Development of multi-well pads in conjunction with longer laterals, well spacing, and completion techniques allows EQT to maximize recoveries per acre while reducing the overall environmental surface footprint of the Company’s drilling operations.
The Company's midstream assets span a wide area of the Marcellus, Upper Devonian and Utica Shales in southwestern Pennsylvania, northern West Virginia and southeastern Ohio. This footprint provides a competitive advantage that uniquely positions the Company for continued growth. EQM and RMP intend to capitalize on the growing need for gathering, transmission and water infrastructure in this region, including the need for midstream header connectivity to interstate pipelines in Pennsylvania, West Virginia and Ohio.
The Company’s board of directors has formed a committee to evaluate options for addressing the Company’s sum-of-the-parts discount. The board will announce a decision by the end of March, 2018, after considering the committee’s recommendation.
See “Capital Resources and Liquidity” in Item 7, “Management’s"Management's Discussion and Analysis of Financial Condition and Results of Operations”Operations" for a discussion of this Annual Reportour accounting policies and significant assumptions related to accounting for gas, NGL and oil producing activities and our accounting policies and processes related to impairment reviews for proved and unproved property.
Segment and Geographical Information
Our operations consist of one reportable segment. We have a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments. We measure financial performance as a single enterprise and not on Form 10-K for details regardingan area-by-area basis. Substantially all of our assets and operations are located in the Company’s capital expenditures.Appalachian Basin.
Reserves
The following tables summarize our proved developed and undeveloped natural gas, NGLs and crude oil reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by product and play. Substantially all of our reserves reside in continuous accumulations.
| | | | | | | | | | | | | | | | | |
| December 31, 2020 |
| | Natural Gas | | NGLs and Crude Oil | | Total |
| (Bcf) | | (MMbbl) | | (Bcfe) |
| Proved developed reserves | 12,750 | | | 148 | | | 13,641 | |
| Proved undeveloped reserves | 6,115 | | | 8 | | | 6,161 | |
| Total proved reserves | 18,865 | | | 156 | | | 19,802 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 |
| Marcellus | | Upper Devonian | | Ohio Utica | | Other | | Total |
| (Bcfe) |
| Proved developed reserves | 11,943 | | | 839 | | | 757 | | | 102 | | | 13,641 | |
| Proved undeveloped reserves | 6,061 | | | — | | | 100 | | | — | | | 6,161 | |
| Total proved reserves | 18,004 | | | 839 | | | 857 | | | 102 | | | 19,802 | |
The following table summarizes our proved developed and undeveloped reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by state.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 |
| Pennsylvania | | West Virginia | | Ohio | | | | Total |
| (Bcfe) |
| Proved developed producing reserves | 9,590 | | | 2,749 | | | 757 | | | | | 13,096 | |
| Proved developed non-producing reserves | 538 | | | 7 | | | — | | | | | 545 | |
| Proved undeveloped reserves | 4,465 | | | 1,596 | | | 100 | | | | | 6,161 | |
| Total proved reserves | 14,593 | | | 4,352 | | | 857 | | | | | 19,802 | |
| | | | | | | | | |
| Gross proved undeveloped drilling locations | 201 | | | 73 | | | 5 | | | | | 279 | |
| Net proved undeveloped drilling locations | 169 | | | 65 | | | 5 | | | | | 239 | |
Our 2020 total proved reserves increased by 2.3 Tcfe, or 13%, compared to 2019 due to extensions, discoveries and other additions of 3,446 Bcfe and the acquisition of 1,381 Bcfe from the Chevron Acquisition, partly offset by production of 1,498 Bcfe, revisions to previous estimates of 739 Bcfe and divestitures of 257 Bcfe. We have an additional 13 Tcfe of reserves that meet the definition of proved reserves, except they are planned to be developed beyond five years and are therefore not included in the current estimate of proved reserves.
During 2020, we conducted a study of our reserves areas to determine the reliability of the technology used in calculating our reserves. This study demonstrated that technologies used in the course of our reserves determination are reliable, provide reasonable certainty of future performance and economics of our wells, and conform to booking practices when using reliable technologies. The technologies used in the estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well logs, geologic maps, core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation and application of statistical analysis.
Proved undeveloped reserves increased by 1,136 Bcfe, or 23%, in 2020 from 2019. The following table provides a rollforward of our proved undeveloped reserves.
| | | | | |
| Proved Undeveloped Reserves |
| (Bcfe) |
| Balance at January 1, 2020 | 5,025 | |
| Conversions into proved developed reserves | (2,102) | |
| Acquisition of in-place reserves | 171 | |
| Revision of previous estimates (a) | (355) | |
| Extensions, discoveries and other additions (b) | 3,422 | |
| Balance at December 31, 2020 | 6,161 | |
(a)Composed of (i) negative revisions of 510 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of changes to our development plan which included 245 Bcfe from lower pricing that impacted well economics, shifting capital from the Ohio Utica, to Pennsylvania and West Virginia Marcellus and 265 Bcfe as a result of continued implementation of our combo-development strategy; and (ii) positive revisions of 155 Bcfe due primarily to changes in working interests and net revenue interests as well as revisions to type curves.
(b)Composed of (i) 2,096 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved using reliable technologies which expanded the number of our technically proven locations; (ii) 1,295 Bcfe due to additions
associated with directly offsetting development; and (ii) 31 Bcfe from the extension of lateral lengths of proved undeveloped reserves.
As of December 31, 2020, we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.
See Note 18 to the Consolidated Financial Statements for further discussion of the preparation of, and year-over-year changes in, our reserves estimate and calculation of our standardized measure of estimated future net cash flows from natural gas and crude oil reserves.
As of December 31, 2020, the standardized measure of our estimated future net cash flows from natural gas and crude oil reserves, which is calculated using average first-day-of-the-month closing prices for the prior twelve months (which is referred to as SEC pricing), was $3,366 million as described in Note 18 to the Consolidated Financial Statements. If the prices used in the calculation of the standardized measure instead reflected five-year strip pricing as of December 31, 2020 and held constant thereafter using (i) the NYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp. M-2, for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the standardized measure, and with all other assumptions held constant, our total proved reserves would be 20,296 Bcfe, the standardized measure of our discounted net future cash flows after taxes of our proved reserves would be $8,952 million, and the discounted future net cash flows before taxes would be $10,152 million. The average realized product prices weighted by production over the remaining lives of the properties would be $27.18 per barrel of oil, $13.55 per barrel of NGL and $2.075 per Mcf of gas (as compared to $20.94 per barrel of oil, $11.97 per barrel of NGL and $1.38 per Mcf of gas using SEC pricing, as described in Note 18). The NYMEX strip price proved reserves and related metrics are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with “SEC pricing” proved reserves and do not comply with SEC pricing assumptions. We believe that the presentation of reserve volumes and related metrics using NYMEX forward strip prices provides investors with additional useful information about our reserves because the forward prices are based on the market’s forward-looking expectations of oil and gas prices as of a certain date. The price at which we can sell our production in the future is the major determinant of the likely economic producibility of our reserves. We hedge substantial amounts of future production based upon futures prices. In addition, we use such forward-looking market-based data in developing our drilling plans, assessing our capital expenditure needs and projecting future cash flows. While NYMEX strip prices represent a consensus estimate of future pricing, such prices are only an estimate and not necessarily an accurate projection of future oil and gas prices. Actual future prices may vary significantly from the NYMEX prices; therefore, actual revenue and value generated may be more or less than the amounts disclosed. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC pricing, when considering our reserves.
Based on our mix of proved undeveloped and probable reserves, we estimate that we have an undeveloped drilling inventory of approximately 1,660 net locations in Pennsylvania and West Virginia Marcellus. At our current drilling pace, these net locations provide more than 15 years of drilling inventory based on net undeveloped Marcellus acres, average expected lateral length of 12,000 feet and well spacing of 1,000 feet. We believe that our combo-development strategy, coupled with our undeveloped inventory located in a premier core asset base, will lead to sustainable free cash flow generation and higher returns on invested capital.
The following table summarizes our capital expenditures for reserve development.
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | | 2019 | | 2018 |
| (Millions) |
Marcellus (includes Upper Devonian) | $ | 737 | | | $ | 1,184 | | | $ | 1,889 | |
| Utica | 102 | | | 193 | | | 360 | |
| Total | $ | 839 | | | $ | 1,377 | | | $ | 2,249 | |
Lease operating costs, excluding production taxes, for the years ended December 31, 2020, 2019 and 2018 was $0.07, $0.06 and $0.07, respectively.
Properties
The majority of our acreage is held by lease or occupied under perpetual easements or other rights acquired, for the most part, without warranty of underlying land titles. Approximately 24% of our total gross acres is developed. We retain deep drilling rights on the majority of our acreage.
The following table summarizes our acreage disaggregated by state.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 |
| Pennsylvania | | West Virginia | | Ohio | | | | Total |
| Total gross productive acreage | 319,504 | | | 84,374 | | | 46,688 | | | | | 450,566 | |
| Total gross undeveloped acreage | 818,345 | | | 448,401 | | | 125,995 | | | | | 1,392,741 | |
| Total gross acreage | 1,137,849 | | | 532,775 | | | 172,683 | | | | | 1,843,307 | |
| | | | | | | | | |
| Total net productive acreage | 289,820 | | | 83,720 | | | 33,906 | | | | | 407,446 | |
| Total net undeveloped acreage | 709,845 | | | 352,402 | | | 109,115 | | | | | 1,171,362 | |
| Total net acreage | 999,665 | | | 436,122 | | | 143,021 | | | | | 1,578,808 | |
| | | | | | | | | |
| Average net revenue interest of proved developed reserves | 72.9 | % | | 83.0 | % | | 48.8 | % | | | | 72.7 | % |
We have an active lease renewal program in areas targeted for development. In the event that production is not established or we take no action to extend or renew the terms of our leases, 71,322, 69,813 and 40,958 of our net undeveloped acreage as of December 31, 2020 will expire in the years ending December 31, 2021, 2022 and 2023, respectively.
The following tables summarize our productive and in-process natural gas wells. We had no productive or in-process oil wells as of December 31, 2020.
| | | | | | | |
| December 31, 2020 |
| Productive wells: | | | |
| Total gross | 3,203 | | | |
| Total net | 2,852 | | | |
| In-process wells: | | | |
| Total gross | 392 | | | |
| Total net | 373 | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 |
| Pennsylvania | | West Virginia | | Ohio | | | | Total |
| Total gross productive wells (a) | 2,252 | | | 685 | | | 266 | | | | | 3,203 | |
| Total net productive wells | 2,059 | | | 659 | | | 134 | | | | | 2,852 | |
(a)Of our total gross productive wells, there are 613 gross conventional wells in Pennsylvania and 4 gross conventional wells in West Virginia. We have no gross conventional wells in Ohio.
The following table summarizes our net development wells drilled. There were no net productive or net dry exploratory wells drilled during the years ended December 31, 2020, 2019 and 2018.
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | | | |
| | | | | |
| | | | | |
| Net development wells: | | | | | |
| Productive | 120 | | | 145 | | | 210 | |
| Dry (a) | — | | | — | | | 5 | |
(a)Dry development wells are related primarily to non-core wells that we no longer plan to drill to depth or complete, acquired wells with mechanical integrity issues and wells that have been plugged and abandoned due to future mining operations or mechanical integrity issues.
During 2020, we commenced drilling operations (spud) on 88 gross wells (84 net), including 66 Pennsylvania Marcellus gross wells (65 net), 17 West Virginia Marcellus gross wells (16 net) and 5 Ohio Utica gross wells (3 net).
Our sales volumes in 2020 from the Marcellus play, including the Upper Devonian play, were 1,315 Bcfe. The following table summarizes our produced and sold volumes by state.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pennsylvania | | West Virginia | | Ohio | | Other (a) | | Total |
| (MMcfe) |
| Produced and sold natural gas, NGLs and oil for the years ended December 31, | | | | | | | | | |
| 2020 | 1,051,869 | | | 267,708 | | | 178,215 | | | — | | | 1,497,792 | |
| 2019 | 1,001,973 | | | 274,378 | | | 231,545 | | | — | | | 1,507,896 | |
| 2018 | 922,033 | | | 323,976 | | | 209,428 | | | 32,252 | | | 1,487,689 | |
(a)Primarily Kentucky and Virginia.
Markets and Customers
No single customer accountedNatural Gas Sales. Natural gas is a commodity and, therefore, we typically receive market-based pricing. The market price for more than 10%natural gas in the Appalachian Basin is typically lower relative to NYMEX Henry Hub, Louisiana (the location for pricing NYMEX natural gas futures) as a result of EQT's total operating revenues for 2017 and 2016. One customer withinincreased supply of natural gas in the EQT Production segment accounted for approximately 10%Northeast United States. To protect cash flow from undue exposure to the risk of EQT's total operating revenues in 2015. The Company believes that the losschanging commodity prices, we hedge a portion of this customer would not have a material adverse effect on its business because alternative customersour forecasted natural gas production at, for the Company'smost part, NYMEX natural gas are available.prices. For information on our hedging strategy and our derivative instruments, refer to "Commodity Risk Management" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations," Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 3 to the Consolidated Financial Statements.
Natural Gas Sales: The Company’sNGLs Sales. We primarily sell NGLs recovered from our natural gas production. We primarily contract with MarkWest Energy Partners, L.P. (MarkWest) to process our natural gas and extract from the produced natural gas is soldheavier hydrocarbon streams (consisting predominately of ethane, propane, isobutane, normal butane and natural gasoline). We also contract with MarkWest to market a portion of our NGLs. In addition, we have contractual arrangements with Williams Ohio Valley Midstream LLC to process our natural gas and market a portion of our NGLs.
Average Sales Price. The following table presents our average sales price per unit of natural gas, NGLs and oil, with and without the effects of cash settled derivatives, as applicable.
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Natural gas ($/Mcf): | | | | | |
| Average sales price, excluding cash settled derivatives | $ | 1.73 | | | $ | 2.48 | | | $ | 3.04 | |
| Average sales price, including cash settled derivatives | 2.37 | | | 2.65 | | | 2.89 | |
| NGLs, excluding ethane ($/Bbl): | | | | | |
| Average sales price, excluding cash settled derivatives | $ | 20.51 | | | $ | 23.63 | | | $ | 37.63 | |
| Average sales price, including cash settled derivatives | 20.39 | | | 25.82 | | | 36.56 | |
| Ethane ($/Bbl): | | | | | |
| Average sales price, excluding cash settled derivatives | $ | 3.48 | | | $ | 6.16 | | | $ | 8.09 | |
| Average sales price, including cash settled derivatives | 3.48 | | | 7.18 | | | 8.09 | |
| Oil ($/Bbl): | | | | | |
| Average sales price | $ | 25.57 | | | $ | 40.90 | | | $ | 52.70 | |
| Natural gas, NGLs and oil ($/Mcfe): | | | | | |
| Average sales price, excluding cash settled derivatives | $ | 1.77 | | | $ | 2.51 | | | $ | 3.15 | |
| Average sales price, including cash settled derivatives | 2.37 | | | 2.69 | | | 3.01 | |
For additional information on pricing, see "Average Realized Price Reconciliation" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Natural Gas Marketing. EQT Energy, LLC, our indirect, wholly-owned marketing subsidiary, provides marketing services and contractual pipeline capacity management services primarily for our benefit. EQT Energy, LLC also engages in risk management and hedging activities to limit our exposure to shifts in market prices.
Customers. We sell natural gas and NGLs to marketers, utilities and industrial customers located in the Appalachian Basin and in the markets availablethat are accessible through the Company's currentour transportation portfolio, which includes marketsparticularly where there is expected future demand growth, such as in the Gulf Coast, Midwest and Northeast United States. Natural gas is a commodityStates and thereforeCanada. As of December 31, 2020, approximately 60% of our sales volumes reach markets outside of Appalachia. We do not depend on any single customer and believe that the Company typically receives market-based pricing. The market price for natural gas in the Appalachian Basin is lower relativeloss of any one customer would not have an adverse effect on our ability to the price at Henry Hub,
Louisiana (the location for pricing NYMEX natural gas futures) as a result of the increased supply of natural gas in the Appalachian Basin. In order to protect cash flow from undue exposure to the risk of changing commodity prices, the Company hedges a portion of its forecasted natural gas production, most of which is hedged at NYMEX natural gas prices. The Company’s hedging strategy and information regarding its derivative instruments is set forth under the heading “Commodity Risk Management” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” and in Notes 1 and 7 to the Consolidated Financial Statements.
NGLs Sales: The Company sells NGLs from its own gas production and from gas marketed for third parties. In its Appalachian operations, the Company primarily contracts with MarkWest Energy Partners, L.P. (MarkWest) to process natural gas in order to extract the heavier hydrocarbon stream (consisting predominately of ethane, propane, iso-butane, normal butane and natural gasoline) primarily from EQT Production’s produced gas. The Company also contracts with MarkWest to market a portion of the Company's NGLs. The Company also has contractual processing arrangements with Williams Ohio Valley Midstream LLC to market NGLs on behalf of the Company in its Appalachian operations. In its Permian Basin operations, the Company sells gas to third party processors at a weighted average liquids component price.
The following table presents the average sales price on a per Mcfe basis to EQT Corporation for sales of producedsell our natural gas, NGLs and oil, with and without cash settled derivatives, for the years ended December 31:oil.
|
| | | | | | | | | | | | |
| | | 2017 | | 2016 | | 2015 |
| Average sales price per Mcfe sold (excluding cash settled derivatives) | | $ | 2.98 |
| | $ | 1.99 |
| | $ | 2.38 |
|
| Average sales price per Mcfe sold (including cash settled derivatives) | | $ | 3.04 |
| | $ | 2.47 |
| | $ | 3.09 |
|
In addition, price information for all products is included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” under the caption “Consolidated Operational Data,” and incorporated herein by reference.
EQM Gathering: EQT Production accounted forWe have access to approximately 89% and 84% of EQM Gathering's gathering revenues and volumes, respectively, for 2017.
EQM provides gathering services in two manners: firm service and interruptible service. The fixed monthly fee under a firm contract is referred to as a firm reservation fee, which is recognized ratably over the contract period based on the contracted volume regardless of the amount of natural gas that is gathered. If there is available system capacity, customers can flow gas above the firm commitment volumes for a usage charge per unit at a rate that is generally the same or lower than the firm capacity charge per unit. EQM has firm gas gathering agreements in high pressure development areas with approximately 2.3 Bcf per day of total firm contracted gathering capacity as of December 31, 2017. Including expected future capacity from expansion projects that are not yet fully constructed but for which EQM had entered into firm gathering agreements, approximately 2.42.5 Bcf per day of firm gatheringpipeline takeaway capacity was subscribed underand 0.9 Bcf per day of firm gathering contracts as of December 31, 2017. On EQM's low pressure regulated gathering system, the typical gathering agreement is interruptible and has a one year term with month-to-month roll over provisions terminable upon at least 30 days notice. The rates for gathering service on the regulated system are based on the maximum posted tariff rate and assessed on actual receipts into the gathering system. EQM generally does not take title to the natural gas gathered for its customers but retains a percentage of wellhead natural gas receipts to recover natural gas used to run its compressor stations and other requirements on all of its gathering systems.
EQM Transmission: In 2017, EQT Production accounted for approximately 64% of transmission volumes and 53% of transmission revenues for EQM Transmission. Other customers include local distribution companies, marketers, other independent producers and commercial and industrial users. EQM's transmission system provides these customers with access to adjacent markets in Pennsylvania, West Virginia and Ohio and also provides access to the Mid-Atlantic, Northeastern, Midwestern and Gulf Coast markets in the United States through interconnect capacity with major interstate pipelines.
EQM Transmission generally does not take title to the natural gas transported or stored for its customers. EQM Transmission provides services in two manners: firm service and interruptible service. The fixed monthly fee under a firm contract is referred to as a capacity reservation fee, which is recognized ratably over the contract period based on the contracted volume regardless of the amount of natural gas that is transported or stored.processing capacity. In addition, we are committed to capacity reservation fees, EQM Transmission may also collect usage fees when a firm transmission customer uses the capacity it has reserved under these firm transmission contracts. Where applicable, the usage fees are assessed on the actual volume of natural gas transported on the system. A firm customer is billed an additional usage fee on volumes in excess of firm capacity when the level of natural gas received for delivery from the customer exceeds its reserved capacity. Customers are not assured capacity or service for volumes in excessinitial 1.29 Bcf per day of firm capacity on the applicable pipeline as these volumesMountain Valley Pipeline upon its in-service date. These firm transportation and processing agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.
We have contractually agreed to deliver firm quantities of gas and NGLs to various customers, which we expect to fulfill with production from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to meet commitments for the same priority as interruptible service.
Under interruptible service contracts, customers pay usage fees based on their actual utilization of assets. Customers that have executed interruptible contracts are not assured capacity or service on the applicable systems. To the extent that physical capacity that is contracted for firm service is not fully utilized or excess capacity that has not been contracted for service exists, the system can allocate such capacitynext one to interruptible services.
Including expected future capacity from expansion projects that are not yet fully constructed but for which EQM has entered into firm contracts, approximately 5.1 Bcf per day of transmission capacity and 31.3 Bcf of storage capacity, respectively, were subscribed under firm transmission and storage contractsthree years. The following table summarizes our total gross commitments as of December 31, 2017. EQM Transmission's firm transmission and storage contracts had a weighted average remaining term of approximately 15 years as of December 31, 2017 based on total projected contracted revenues.2020.
| | | | | | | | | | | |
| Natural Gas | | NGLs |
| Years ending December 31, | (Bcf) | | (Mbbl) |
| 2021 | 1,390 | | | 7,814 | |
| 2022 | 917 | | | 2,658 | |
| 2023 | 780 | | | 1,825 | |
| 2024 | 601 | | | 1,830 | |
| 2025 | 388 | | | 1,825 | |
| Thereafter | 2,587 | | | 600 | |
As of December 31, 2017, approximately 89% of EQM Transmission's contracted transmission firm capacity was subscribed by customers under negotiated rate agreements under its tariff. Approximately 9% of EQM Transmission’s contracted transmission firm capacity was subscribed at
Seasonality
Generally, but not always, the recourse rates under its tariff, which are the maximum rates an interstate pipeline may chargedemand for its services under its tariff. The remaining 2% of EQM Transmission’s contracted transmission firm capacity was subscribed at discounted rates, which are less than the maximum rates an interstate pipeline may charge for its services under its tariff.
EQM Transmission has an acreage dedication from EQT pursuant to which EQM Transmission has the right to elect to transport on its transmission and storage system all natural gas produced from wells drilled by EQT under an area covering approximately 60,000 acres in Allegheny, Washingtondecreases during the summer months and Greene Counties in Pennsylvania and Wetzel, Marion, Taylor, Tyler, Doddridge, Harrison and Lewis Counties in West Virginia. EQT has a significant natural gas drilling program in these areas.increases during the winter months. Seasonal anomalies such as mild winters or hot summers may also impact demand.
Natural Gas Marketing: EQT Energy, LLC (EQT Energy) and Rice Energy Marketing LLC, EQT's indirect wholly owned marketing subsidiaries, provide marketing services and contractual pipeline capacity management for the benefit of EQT Production and third parties. The marketing subsidiaries also engage in risk management and hedging activities on behalf of EQT Production, the objective of which is to limit the Company’s exposure to shifts in market prices.
RMP Gathering: During the year ended December 31, 2017, EQT and Rice, prior to the Rice Merger, represented substantially all of RMP Gathering’s gathering and compression revenues.
RMP Gathering has secured dedications from certain EQT affiliates under various fixed price per unit gathering and compression agreements covering (i) approximately 246,000 gross acres of EQT's acreage position in Washington and Greene Counties, Pennsylvania, and (ii) subject to certain exceptions and limitations pursuant to the gas gathering and compression agreements, any future acreage certain affiliates of EQT acquire within these counties.
RMP Water Services: During the year ended December 31, 2017, EQT and Rice, prior to the Rice Merger, represented approximately 96% of RMP Water's water service revenues.
RMP Water has the exclusive right to provide certain fluid handling services to EQT Production until December 22, 2029, and from month to month thereafter. The fluid handling services include the exclusive right to provide fresh water for well completions operations and to collect and recycle or dispose of flowback and produced water within areas of dedication in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio. RMP Water also provides water services to third parties under fee-based contracts to support well completion activities.
Competition
NaturalOther natural gas producers compete with us in the acquisition of properties,properties; the search for, and development of, reserves,reserves; the production transportation and sale of natural gas and NGLsNGLs; and the securing of services, labor, equipment and equipmenttransportation required to conduct operations. CompetitorsOur competitors include independent oil and gas companies, major oil and gas companies, and individual producers, operators and operators withinmarketing companies and outside of the Appalachian Basin.
Competition for natural gas gathering, transmission and storage volumes is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, service levels, location, reputation and fuel efficiencies. Key competitors in the natural gas transmission and storage market includeother energy companies that own major natural gas pipelines. Key competitorsproduce substitutes for gathering systems include companiesthe commodities that own major natural gas pipelines, independent gas gatherers and integrated energy companies. EQT competes with numerous companies when marketing natural gas and NGLs. Some of these competitors are affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users.we produce.
Key competitors for water services include natural gas producers that develop their own water distribution systems in lieu of employing the Company's assets and other natural gas midstream companies. Our ability to attract volumes to the water services business depends on the Company's ability to evaluate and select suitable projects and to consummate transactions in a highly competitive environment.
Regulation
Regulation of the Company’s Operations
EQT Production’sour Operations. Our exploration and production operations are subject to various types of federal, state and local laws and regulations, including regulations related to the following: the location of wells; the method of drilling, well construction, well stimulation, hydraulic fracturing and casing design; water withdrawal and procurement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the plugging and abandoning of wells; the calculation, reporting and disbursement of royalties and taxes; and the gathering of production in certain circumstances. These regulations, and any delays in obtaining related authorizations, may affect the costs and timing of developing EQT Production’sour natural gas resources.
EQT Production’sOur operations are also subject to conservation and correlative rights regulations, including the following: regulation of the size of drilling and spacing units or field rule units; setbacks; the number of wells that may be drilled in a unit or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of natural gas properties. Kentucky, Ohio Virginia and, for Utica or other deep wells, West Virginia allow the statutory pooling or unitization of tracts to facilitate development and exploration. In West Virginia, the Companywe must rely on voluntary pooling of lands and leases for Marcellus and Upper Devonian acreage. In 2013, the Pennsylvania, legislature enacted lease integration legislation which authorizes joint development of existing contiguous leases, and Texas permits similar joint development.leases. In addition, state conservation and oil and gas laws generally limit the venting or flaring of natural gas, and Texas sets allowables ongas. Various states also impose certain regulatory requirements to transfer wells to third parties or discontinue operations in the amountevent of production permitted from a well.divestitures by us.
The Company's
We maintain limited gathering and transmission operations that are subject to various types of federal and state environmental laws and local zoning ordinances, including the following: air permitting requirements for compressor station and dehydration units and other permitting requirements; erosion and sediment control requirements for compressor station and pipeline construction projects; waste management requirements and spill prevention plans for compressor stations; various recordkeeping and reporting requirements for air permits and waste management practices; compliance with safety regulations;regulations, including regulations by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration; and siting and noise regulations for compressor stations and transmission facilities.stations. These regulations may increase the costs of operating existing pipelines and compressor stations and increase the costs of, and the time to develop, new or expanded pipelines and compressor stations.
The Company's interstate natural gas transmission and storage operations are regulated by the FERC, and certain gathering lines are also subject to rate regulation by the FERC. The FERC approves tariffs that establish EQM’s rates, cost recovery mechanisms and other terms and conditions of service applicable to its FERC-regulated assets. The fees or rates established under EQM’s tariffs are a function of its costs of providing services to customers, including a reasonable return on invested capital. The FERC’s authority over transmission operations also extends to: storage and related services; certification and construction of new interstate transmission and storage facilities; extension or abandonment of interstate transmission and storage services and facilities; maintenance of accounts and records; relationships between pipelines and certain affiliates; terms and conditions of service; depreciation and amortization policies; acquisition and disposition of facilities; the safety of pipelines; and initiation and discontinuation of services.
In 2010, the U.S. Congress adopted comprehensive financial reform legislation that establishesestablished federal oversight and regulation of the over-the-counterOTC derivative market and entities, such as the Company,us, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing this legislation. AsAmong other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivative activities. Although some of the filing date of this Annual Report on Form 10-K,rules necessary to implement the CFTC had adopted and implemented many final rules that impose regulatory obligations on all market participants, including the Company, such as recordkeeping and certain reporting obligations. Other CFTC rules that may be relevant to the CompanyDodd-Frank Act have yet to be finalized. Because significant CFTCadopted, regulators have issued numerous rules relevantunder the Dodd-Frank Act, including a rule establishing an “end-user” exception to mandatory clearing (End-User Exception), a rule regarding margin for certain uncleared swaps (Margin Rule) and a rule imposing federal position limits on certain futures contracts relating to energy products, including natural gas (Position Limits Rule).
We qualify as a “non-financial entity” for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities haveare not been adoptedsubject to mandatory clearing or implemented, it is not possible at this timethe margin requirements imposed in connection with mandatory clearing, although we are subject to predict the extentcertain recordkeeping and reporting obligations associated with such rule. We also qualify as a “non-financial end user” for purposes of the impactMargin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, although the Position Limits Rule does not go into effect with respect to energy products until January 1, 2022, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under the Position Limits Rule and will not be subject to the limitations under such rule. However, many of our hedge counterparties and other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule, which may affect the pricing and/or availability of derivatives for us. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations on the Company’s hedging program or regulatory compliance obligations. The Company has experienced increased, and anticipates additional, compliance costs and changesrelated to current market practices as participants continuederivatives which apply to adaptour transactions with counterparties subject to a changing regulatory environment.such foreign regulations.
Regulators periodically review or audit the Company’sour compliance with applicable regulatory requirements. The Company anticipatesWe anticipate that compliance with existing laws and regulations governing current operations will not have a material adverse effect upon itsour capital expenditures, earnings or competitive position. Additional proposals that affect the oil and gas industry are regularly considered by the U.S. Congress, the states, regulatory agencies and the courts. The CompanyWe cannot predict when or whether any such proposals may become effective or the effect that such proposals may have on us.
The following is a summary of some of the Company.existing laws, rules and regulations to which our business operations are subject.
Natural Gas Sales and Transportation. The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC's regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas.
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties of over $1 million per day for each violation and disgorgement of profits associated with any violation. While our production activities have not been regulated by the FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale
to the extent such transactions use, contribute to or may contribute to the formation of price indices. In addition, Congress may enact legislation or the FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.
The CFTC also holds authority to monitor certain segments of the physical and futures energy commodities market including natural gas, NGLs and oil. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.
The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of natural gas and release of our natural gas pipeline capacity. Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide non-unduly discriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. The FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas-related activities.
Under the FERC's current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. The FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of FERC-jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC's determinations as to the classification of facilities are done on a case-by-case basis. To the extent that the FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and, depending on the scope of that decision, our costs of transporting gas to point of sale locations may increase. We believe that the third-party natural gas pipelines on which our gas is gathered meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. However, the distinction between the FERC-regulated transportation services and federally unregulated gathering services could be subject to potential litigation, so the classification and regulation of those gathering facilities are subject to change based on future determinations by the FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Oil and NGLs Price Controls and Transportation Rates. Sales prices of oil and NGLs are not currently regulated and are made at market prices. Our sales of these commodities are, however, subject to laws and to regulations issued by the Federal Trade Commission (FTC) prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of over $1 million per day per violation. Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.
The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Some of our transportation of oil and NGLs is through FERC-regulated interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC's regulation of crude oil and NGLs transportation rates may tend to increase the cost of transporting crude oil and NGLs by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The FERC published the five-year index level for 2021-2026 in December 2020. We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crude oil production from our crude oil producing operations.
Environmental, Health and Safety Regulation
TheRegulation. Our business operations of the Company are also subject to variousnumerous stringent federal, state and local environmental, health and safety laws and regulations pertaining to, among other things, the release, emission or discharge of materials into the environment; the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes); the safety of employees and the general public; pollution; site remediation; and preservation or protection of human health and safety, natural resources, wildlife and the environment. The CompanyWe must take into account environmental, health and safety regulations in, among other things, planning, designing, constructing, operating and plugging and abandoning wells pipelines and related facilities. Violations of these laws can result in substantial administrative, civil and criminal penalties. These laws and regulations may require the acquisition of permits before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands and other protected areas or areas with endangered or threatened species restrictions; require some form of remedial action to prevent or mitigate pollution from former operations, such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations. In addition, these laws and regulations may restrict the rate of production.
Moreover, the trend has been for stricter regulation of activities that have the potential to affect the environment. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, the states, local governments and the courts. We cannot predict when or whether any such proposals may become effective. Therefore, we are unable to predict the future costs or impact of compliance. The Company hasregulatory burden on the industry increases the cost of doing business and affects profitability. We have established procedures, however, for the ongoing evaluation of itsour operations to identify potential environmental exposures and to assuretrack compliance with regulatory policies and procedures.
The following is a summary of the more significant existing environmental and occupational health and workplace safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our financial condition, earnings or cash flows.
Hazardous Substances and Waste Handling. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the "Superfund" law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, despite the "petroleum exclusion" of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we generate materials in the course of our operations that may be regulated as hazardous substances based on their characteristics; however, we are unaware of any liabilities arising under CERCLA for which we may be held responsible that would materially and adversely affect us.
The Resource Conservation and Recovery Act (RCRA) and analogous state laws establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA, or state agencies under RCRA's less stringent nonhazardous solid waste provisions, or under state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. In April 2019, following litigation and a resulting consent decree related to the EPA's requirements under RCRA to review oil and gas waste regulations, the EPA determined that revisions to the regulations were not required, concluding that any adverse effects related to oil and gas waste were more appropriately and readily addressed within the framework of existing state regulatory programs. Any changes to state or federal programs could result in an increase in our costs to manage and dispose waste, which could have a material adverse effect on our results of operations and financial condition.
We currently own, lease or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe that we have used operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including offsite locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous
owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. We are able to control directly the operation of only those wells with respect to which we act or have acted as operator. The failure of a prior owner or operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to us as current owner or operator under CERCLA. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, regardless of fault, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or waste pit closure operations to prevent future contamination.
Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act (CWA), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state equivalent agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (Corps). In June 2015, the EPA and the Corps issued a final rule defining the scope of the EPA's and the Corps' jurisdiction over waters of the United States (WOTUS), which was stayed nationwide in October 2015 pending resolution of several legal challenges. The EPA and the Corps proposed a rule in July 2017 to repeal the WOTUS rule and announced their intent to issue a new rule defining the CWA's jurisdiction. In January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction to hear challenges to the WOTUS rule resides with the federal district courts, which lifted the stay and resulted in a patchwork application of the rule in some states, but not in others. In October 2019, the EPA issued a final rule repealing the WOTUS rule and the repeal rule became effective in December 2019. In April 2020, the EPA and the Corps published the Navigable Waters Protection Rule (NWPR), which narrowed the definition of WOTUS to four categories of jurisdictional waters and includes twelve categories of exclusions, including groundwater. A coalition of states and cities, environmental groups, and agricultural groups have challenged the NWPR and a federal district court in Colorado stayed implementation of the rule. The stay is limited to application of the rule in Colorado; the rule has taken effect in all other states. In addition, in an April 2020 decision defining the scope of the CWA that was handed down just days after the NWPR was published, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. The Court rejected the EPA and Corps’ assertion that groundwater should be totally excluded from the CWA. The Court’s decision is expected to bolster challenges to the NWPR. On January 20, 2021, the Biden Administration announced it will review the NWPR in accordance with the January 20, 2021 Executive Order that revokes President Trump’s Executive Order 13778, which required review and reversal of the WOTUS rule. The EPA and the Corps have requested to stay the litigation over the NWPR during the agencies’ review of the rule. To the extent a revised rule expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects. Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or stormwater and to develop and implement spill prevention, control and countermeasure (SPCC) plans in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.
Air Emissions. The federal Clean Air Act (CAA) and comparable state laws regulate the emission of air pollutants from many sources, such as, for example, tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre‑approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or use specific equipment or technologies to control emissions of certain pollutants, the costs of which could be significant. The need to obtain permits has the potential to delay the development of our oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new facilities or modify existing facilities in any newly designated non-attainment areas. Compliance with more stringent standards and other environmental regulations could delay or prohibit our ability to obtain permits for our operations or require us to install additional pollution control equipment, the costs of which could be significant.
Climate Change and Regulation of "Greenhouse Gas" Emissions. In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (GHG) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (PSD) construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their
GHG emissions are required to meet "best available control technology" standards established by the states or, in some cases, by the EPA on a case‑by‑case basis. These CAA requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.
In June 2016, the EPA finalized new regulations that established New Source Performance Standards (NSPS), known as Subpart OOOOa, for methane and volatile organic compounds (VOC) from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized amendments to the 2016 Subpart OOOOa standards, known as the Reconsideration Rule, that reduce the 2016 rule's fugitive emissions monitoring requirements and expand exceptions to pneumatic pump requirements, among other changes. Various industry and environmental groups have separately challenged both the methane requirements and the EPA's attempts to delay the implementation of the rule. In addition, in April 2018, several states filed a lawsuit seeking to compel the EPA to issue methane performance standards for existing sources in the oil and natural gas source category. In September 2020, the EPA issued a rule to revise Subpart OOOOa to rescind the methane-specific requirements for certain oil and natural gas sources in the production and processing segments, known as the Review Rule. Both the Reconsideration Rule and the Review Rule are subject to pending litigation. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the Reconsideration Rule by September 2021 and consider revising the Review Rule. As a result of the actions described above, we cannot predict with certainty the scope of any final methane regulations or the costs for complying with federal methane regulations.
At the state level, several states have proceeded with regulation targeting GHG emissions. For example, in June 2018, the Pennsylvania Department of Environmental Protection (PADEP) released revised versions of GP-5 and GP-5A, Pennsylvania's general air permits applicable to processing plants and well site operations, among other facilities. These permits apply to new or modified sources constructed on or after August 8, 2018, with emissions below certain specified thresholds. GP-5 and GP-5A impose "best available technology" (BAT) standards, which are in addition to, and in many cases more stringent than, the federal NSPS. These BAT standards include a 200 ton per year limit on methane emissions, above which a BAT requirement for methane emissions control applies. Moreover, in May 2020, the Pennsylvania Environmental Quality Board (EQB) published in the Pennsylvania Bulletin a proposed rulemaking for the control of emissions of VOCs and other pollutants for existing sources. EQB accepted public comments on the proposed rulemaking through July 2020; however, a final rulemaking has yet to be approved by the EQB. State regulations such as these could impose increased compliance costs on our operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of federal legislation in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. In October 2019, Pennsylvania Governor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join the Regional Greenhouse Gas Initiative (RGGI), a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In September 2020, the EQB approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020. Based on the current timeline for implementation, final rulemaking is expected to be sent to the EQB for review and approval in the fourth quarter of 2021, with the first year of compliance anticipated to begin in 2022. Assuming Pennsylvania ultimately becomes a member of the RGGI in 2022, as currently anticipated, it will result in increased operating costs if we are required to purchase emission allowances in connection with our operations.
On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets (Paris Agreement). The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does not impose any binding obligations on its participants. In August 2017, the U.S. Department of State officially informed the United Nations of the United States' intent to withdraw from the Paris Agreement, with such withdrawal becoming effective in November 2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which will become effective in 30 days from such date.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated
with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.
Notwithstanding potential risks related to climate change, the International Energy Agency estimates that natural gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades, in large part driven by the fact that natural gas produces significantly less CO2 compared to other fossil fuels - up to 50% less than coal and 20-30% less than oil, according to the U.S. Energy Information Administration. Nonetheless, recent activism directed at shifting funding away from fossil fuel companies could result in limitations or restrictions on certain sources of funding for the sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.
Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations.
Hydraulic Fracturing Activities. Vast quantities of natural gas deposits exist in shale and other formations. It is customary in the Company’sour industry to recover natural gas from these shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into a shale gas formation. These deeper formations are geologically separated and isolated from fresh ground water supplies by overlying rock layers. The Company’sOur well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers. To assess water sources near our drilling locations, the Company conductswe conduct baseline and, as appropriate, post-drilling water testing at all water wells within at least 2,500 feet of the Company'sour drilling pads. Legislative
Hydraulic fracturing typically is regulated by state oil and natural gas agencies, but the EPA has asserted federal regulatory efforts atauthority pursuant to the federal Safe Drinking Water Act (SDWA) over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities. The EPA also finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules.
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in someJanuary 2016, the PADEP issued new rules establishing stricter disposal requirements for wastes associated with hydraulic fracturing activities, which include, among other things, a requirement to obtain new permits, or closure, of centralized impoundments used for the storage of drill cuttings and waste fluids. Further, these rules include requirements relating to storage tank security, secondary containment for storage vessels, construction rules for gathering lines and horizontal drilling under streams and temporary transport lines for freshwater and wastewater. Additionally, in January 2020, the EQB approved a well permit fee increase from $5,000 to $12,500 for all unconventional wells. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to renderban hydraulic fracturing altogether. If new or more stringent permitting and compliance requirements for hydraulic fracturing. If passed into law,federal, state or local legal restrictions relating to the additional permitting requirements for hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from constructing wells.
Occupational Safety and Health Act. We are also subject to the requirements of the federal Occupational Safety and Health Act (OSHA), as amended, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA's hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens.
Endangered Species Act and Migratory Bird Treaty Act. The federal Endangered Species Act (ESA) provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may increasebe imposed on activities adversely affecting that species' habitat. Similar protections are offered to migratory birds under the costMigratory Bird Treaty Act. The U.S. Fish and Wildlife Service (FWS) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. In August 2019, the FWS and National Marine Fisheries Service issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states and environmental groups have challenged the three rules and litigation remains pending. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations; the amended regulations are subject to ongoing litigation. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (MBTA), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or limitpurchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the Company’sU.S. In January 2021, the Department of the Interior finalized a rule limiting application of the MBTA; however, the Department of the Interior under President Biden delayed the effective date of the rule and opened a public comment period for further review. Future implementation of the rules implementing the ESA and the MBTA are uncertain. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas development. Further, the designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to obtain permits to construct wells.develop and produce reserves.
See Note 2016 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.
Climate ChangeHuman Capital Resources
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phasesAs of discussion or implementation. The EPA and various states have issued a numberDecember 31, 2020, we had 624 permanent employees, none of proposed and final laws and regulations that limit greenhouse gas emissions. Legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and greenhouse gas legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat generated than other fossil fuels, such as coal. The effect on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
Employees
The Company and its subsidiaries had 2,067 employees at the end of 2017; none arewhom were subject to a collective bargaining agreement. Of our total permanent employee base, 74% were male and 26% were female. The substantial majority of our employees reside in Pennsylvania and West Virginia.
We aim to develop a workforce that produces peer leading results. To further that goal, we have focused on creating a modern, innovative, collaborative and digitally-enabled work environment. In 2019, we simplified our organizational structure and instituted a cloud-based digital work environment with an emphasis on the democratization of data. Our digital work environment serves as our primary platform for communication and collaboration as well as the home for our critical work processes and drives decision-making based on a shared and transparent view of operational data. We use our digital work environment to engage directly with our employees by sharing company updates and personnel accomplishments and internal polling.
We understand that providing employees with the resources and support they need to live a physically, mentally, and financially healthy life is critical for sustaining a workplace of choice. We offer benefits that include subsidized health insurance, a company-contribution and company-match on 401(k) retirement savings, an employee stock purchase plan, paid maternity and paternity leave, flexible work arrangements, volunteer time off, and a company-match on employee donations to qualified non-profits. We also offer our employees the flexibility to elect to work a “9/80” work schedule, under which, during the standard 80-hour pay period, an employee works eight 9-hour days and one 8-hour day (Friday), with a tenth day off (alternative Friday).
In 2020, we launched an “equity-for-all” program, which granted equity awards to all of our permanent full-time employees. With the equity-for-all program, all of our permanent full-time employees have the opportunity to share directly in our financial success. These grants were in addition to, and not in lieu of, existing compensation for these employees.
Availability of Reports and Other Information
The Company makesWe make certain filings with the SEC, including its annual reportour Annual Report on Form 10-K, quarterly reportsQuarterly Reports on Form 10-Q, current reportsCurrent Reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through itsour investor relations website, http://www.eqt.com,ir.eqt.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. The filings are also available atReports filed with the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. These filingsSEC are also available on the internet atSEC's website, http://www.sec.gov.
We also use our Twitter account, @EQTCorp, our Facebook account, @EQTCorporation, and our LinkedIn account, EQT Corporation, as additional ways of disseminating information that may be relevant to investors.
We generally post the following to our investor relations website shortly before or promptly following its first use or release: financially-related press releases, including earnings releases and supplemental financial information; various SEC filings; presentation materials associated with earnings and other investor conference calls or events; and access to live and recorded audio from earnings and other investor conference calls or events. In certain cases, we may post the presentation materials for other investor conference calls or events several days prior to the call or event. For earnings and other conference calls or events, we generally include within our posted materials a cautionary statement regarding forward-looking and non-GAAP financial information as well as non-GAAP to GAAP financial information reconciliations (if available). Such GAAP reconciliations may be in materials for the applicable presentation, in materials for prior presentations or in our annual, quarterly or current reports.
In certain circumstances, we may post information, such as presentation materials and press releases, to our corporate website, www.EQT.com, or our investor relations website to expedite public access to information regarding EQT in lieu of making a filing with the SEC for first disclosure of the information. When permissible, we expect to continue to do so without also providing disclosure of this information through filings with the SEC.
Where we have included internet addresses in this Annual Report on Form 10-K, we have included those internet addresses as inactive textual references only. Except as specifically incorporated by reference into this Annual Report on Form 10-K, information on those websites is not part hereof.
Composition of Segment Operating Revenues
Presented below areThe following table presents total operating revenues for each class of our products and services representing greater than 10% of total operating revenues.services.
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| (Thousands) |
| Operating revenues: | | | | | |
| Sales of natural gas, NGLs and oil | $ | 2,650,299 | | | $ | 3,791,414 | | | $ | 4,695,519 | |
| Gain (loss) on derivatives not designated as hedges | 400,214 | | | 616,634 | | | (178,591) | |
| Net marketing services and other | 8,330 | | | 8,436 | | | 40,940 | |
| Total operating revenues | $ | 3,058,843 | | | $ | 4,416,484 | | | $ | 4,557,868 | |
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Operating Revenues: | | | | | | |
| Sales of natural gas, oil and NGLs (a) | | $ | 2,651,318 |
| | $ | 1,594,997 |
| | $ | 1,690,360 |
|
| Pipeline, water and net marketing services (b) | | 336,676 |
| | 262,342 |
| | 263,640 |
|
| Gain (loss) on derivatives not designated as hedges (a) | | 390,021 |
| | (248,991 | ) | | 385,762 |
|
| Total operating revenues | | $ | 3,378,015 |
| | $ | 1,608,348 |
| | $ | 2,339,762 |
|
| |
(a) | Reported in the EQT Production segment. |
| |
(b) | Reported in the EQM Gathering, EQM Transmission, RMP Gathering and RMP Water segments, with the exception of $65.0 million, $41.0 million and $55.5 million for the years ended December 31, 2017, 2016 and 2015, respectively, which are reported within the EQT Production segment. |
Financial Information about Segments
See Note 6 to the Consolidated Financial Statements for financial information by business segment including, but not limited to, revenues from external customers, operating income and total assets.
Jurisdiction and Year of Formation
The Company isWe are a Pennsylvania corporation formed in 2008 in connection with a holding company reorganization of the former Equitable Resources, Inc.
Financial Information about Geographic Areas
Substantially all of the Company’s assets and operations are located in the continental United States.
Item 1A. Risk Factors
In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. Please noteNote that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.
Summary of Risk Factors
We believe that the risks associated with our business, and consequently the risks associated with an investment in our equity or debt securities, fall within the following six categories:
•Risks Associated with Natural gas, NGLs and oil price volatility, orGas Drilling Operations. As a prolonged period of low natural gas producer, there are risks inherent in our primary business operations. These risks are not necessarily unique to us, but rather, these are risks that most operators in our industry have at least some exposure to.
•Financial and Market Risks. Given that our primary product and source of revenue is the sale of natural gas and NGLs, one of our most material risks is the commodity market and oilthe price of natural gas and NGLs, which is often volatile. Additionally, our operations are capital intensive. Pressures on the market as a whole, or our specific financial
position – whether due to depressed commodity prices, our leverage, our credit ratings or otherwise – could make it difficult for us to obtain the funding necessary to conduct our operations.
•Risks Associated with Our Human Capital, Technology and Other Resources and Service Providers. Our business, and the U.S. energy grid, is predominately operated on a digital system. Our employees rely on our cloud-based digital work environment to communicate and access data that is necessary to conduct our day-to-day operations. While these digital systems enable us to efficiently supply our natural gas and NGLs to the market, they are also susceptible to cyber security threats. Likewise, as a digitally-focused organization, we seek employees with a high degree of both technical skill and digital literacy, and it can be difficult to attract and retain personnel who satisfy these criteria. Further, we predominately operate in the Appalachia Basin, and a substantial majority of our midstream and water services are provided by one provider, EQM Midstream Partners, LP, making us vulnerable to risks associated with operating primarily in one major geographic area and obtaining a substantial amount of our services from a single provider within that operating area.
•Legal and Regulatory Risks. There are many environmental, energy, financial, real property and other regulations that we are required to comply with in the context of conducting our operations, otherwise, we may have an adverse effect uponbe exposed to fines, penalties, investigations, litigation or other legal proceedings. Additionally, negative public perception of us or the natural gas industry, or increasing consumer demand for alternatives to natural gas, could adversely impact our revenue, profitability, future rate of growth, liquidityearnings, cash flows and financial position.
Our revenue, profitability, future rate of growth, liquidity and financial position depend upon the prices for natural gas, NGLs and oil. The prices for natural gas, NGLs and oil•Risks Associated with Strategic Transactions. We have historically been volatile,involved in, and anticipate that we expect this volatilitywill continue to continueexplore, opportunities to create value through strategic transactions, whether through mergers and acquisitions, divestitures, joint ventures or similar business transactions. There are risks inherent in any strategic transaction, and such risks could negatively affect the future. The pricesbenefits, outcomes and synergies anticipated to be obtained from executing such strategic transactions.
•Risks Related to the COVID-19 Pandemic. While we did not experience any material adverse effects from the COVID-19 pandemic in 2020, the severity, magnitude and duration of the COVID-19 pandemic is still uncertain, rapidly changing and difficult to predict. We believe that our principal areas of operational risk resulting from a pandemic are affected by aavailability of service providers and supply chain disruption. Additionally, active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of factorspersonnel and contractors on our drilling sites. We believe that we are following best practices under COVID-19 guidance; however, the potential for transmission still exists, and in certain instances, it may be necessary or determined advisable for us to delay our development operations.
We describe these risks in greater detail below.
Risks Associated with Natural Gas Drilling Operations
Drilling for and producing natural gas is a high-risk and costly activity with many uncertainties. Our future financial position, cash flows and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, which include:including the risk that drilling will not result in commercially viable natural gas production or that we will not recover all or any portion of our investment in drilled wells.
Many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
•delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from permitting, wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;
•shortages of or delays in obtaining equipment, rigs, materials and qualified personnel or in obtaining water for hydraulic fracturing activities;
•equipment failures, accidents or other unexpected operational events;
•lack of available gathering and water facilities or delays in construction of gathering and water facilities;
•lack of available capacity on interconnecting transportation pipelines;
•adverse weather conditions, such as flooding, droughts, freeze-offs, slips, blizzards and seasonal trends; the supply of and demand forice storms;
•issues related to compliance with environmental regulations;
•environmental hazards, such as natural gas NGLs and oil; regional basis differentials; national and worldwide economic and political conditions; new and competing exploratory finds of natural gas, NGLs and oil; the ability to export liquefied natural gas; the effect of energy conservation efforts; the price and availability of alternative fuels; the availability, proximity and capacity of pipelines, other transportation facilities, and gathering, processing and storage facilities; and government regulations, such as regulation of natural gas transportation and price controls.
The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.77 per MMBtu to a low of $1.49 per MMBtu from January 1, 2016 through December 31, 2017, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $60.46 per barrel to a low of $26.19 per barrel during the same period. In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Northeast region in recent years. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, including Appalachian and other market point basis, NGLs andleaks, oil and thus cannot predictdiesel spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the ultimate impactsurface and subsurface environment;
Lower prices for natural gas, NGLs and oil result in lower revenues, operating income and cash flows. Prolonged low, and/or significant or extended further •declines in natural gas, NGLs and oil prices may result in further decreases inmarket prices;
•limited availability of financing at acceptable terms;
•ongoing litigation or adverse court rulings;
•public opposition to our revenues, operating incomeoperations;
•title, surface access, coal mining and cash flows, which may result in reductions in drilling activity, delaysright of way problems; and
•limitations in the construction of new midstream infrastructure and downgrades, or other negative rating actions with respect to our credit ratings. Further declines in prices could also adversely affect the amount ofmarket for natural gas, NGLs and oil that weoil.
Any of these risks can produce economically, which may resultcause a delay in us having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings in future periods. See “Impairment of Oil and Gas Properties and Goodwill” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Natural gas, NGLs and oil price declines have resulted in impairment of certain of our non-core assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance may result in additional write-downs of the carrying amounts of our assets, including goodwill and other long lived intangible assets, which could materially and adversely affect our results of operations in future periods.” under Item 1A, “Risk Factors.” Moreover, a failure to control our development costs during periods of lower natural gas, NGLs and oil prices could have significant adverse effects on our earnings, cash flows and financial position. We are also exposed to the risk of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in derivative contracts with a positive fair value. Further, adverse economic and market conditions could negatively affect the collectability of our trade receivables and cause our hedge counterparties to be unable to perform their obligations or to seek bankruptcy protection.
Increases in natural gas, NGLs and oil prices may be accompanied byprogram or result in increased well drilling costs, increased production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads for our storage assetssubstantial financial losses, personal injury or loss of life, damage to or destruction of property, natural resources and increased end-user conservationequipment, pollution, environmental contamination or conversion to alternative fuels. Significant natural gas price increases may subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including swap, collarloss of wells and option agreements and exchange-traded instruments) which would potentially require us to post significant amounts of cash collateral with our hedge counterparties. The cash collateral provided to our hedge counterparties, which is interest-bearing, is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related derivative contract. In addition, to the extent we have hedged our current production at prices below the current market price, we are unable to benefit fully from an increase in the price of natural gas.other regulatory penalties.
We may not achieve the intended benefits of the acquisition of Rice and the acquisition may disrupt our current plans or operations.
There can be no assurance that we will be able to successfully integrate Rice’s assets or otherwise realize the expected benefits of the acquisition of Rice. In addition, our business may be negatively impacted if we are unable to effectively manage our expanded operations going forward. The integration has required and will continue to require significant time and focus from management and could disrupt current plans and operations, which could delay the achievement of our strategic objectives.
We are subject to risks associated with the operation of our wells pipelines and facilities.
Our business is subject to all of the inherent hazards and risks normally incidental to the operationsdrilling for, drilling, completions, producing, transporting and storing natural gas, NGLs and oil, such as fires, explosions, slips, landslides, blowouts, and well site blowouts, cratering and explosions,cratering; pipe and other equipment and system failures, landslides, fires,failures; delays imposed by, or resulting from, compliance with regulatory requirements; formations with abnormal or unexpected pressures,pressures; shortages of, or delays in, obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities; adverse weather conditions, such as freeze offs of wells and pipelines due to cold weather,weather; issues related to compliance with environmental regulations; environmental hazards, such as natural gas leaks, oil and diesel spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized releases of brine, well stimulation and completion fluids, toxic gases or other pollutants into the environment, especially those that reach surface water or groundwater; inadvertent third partythird-party damage to the Company'sour assets, pollution and environmental risks and natural disasters. We also face various risks or threats to the operation and security of our or third parties’parties' facilities and infrastructure, such as processing plants, compressor stations and pipelines. TheseAny of these risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, equipment and equipment,natural resources, pollution or other environmental damage, loss of hydrocarbons, disruptions to our operations, regulatory investigations and penalties, suspension of our operations, repair and remediation costs, and loss of sensitive confidential information. Moreover, in the event that one or more of these hazards occur, there can be no assurance that a response will be adequate to limit or reduce damage. As a result of these risks, we are also sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that the insurance policies we maintain to limit our liability for such losses will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices or to cover all risks.
Our failure In addition, pollution and environmental risks generally are not fully insurable, and we may elect not to develop, obtain accessinsurance for any or maintain the necessary infrastructure to successfully deliver natural gas, NGLs and oil to market may adversely affect our earnings, cash flows and resultsall of operations.
Our delivery of natural gas, NGLs and oil depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and processing facilities. The capacity of transmission, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our natural gas, NGLs and oil. Competition for access to pipeline infrastructure within the Appalachian Basin is intense, and our ability to secure access to pipeline infrastructure on economic terms could affect our competitive position. The Company’s investment in midstream infrastructure through EQM and RMP is intended to address a lack of capacity on, and access to, existing gathering and transmission pipelines as well as curtailments on such pipelines. Our infrastructure development and maintenance programs can involve significant risks, including those related to timing, cost overruns, operational efficiency, and construction, and these risks can be affected by the availability of capital, materials and a qualified work force, as well as the complexity of construction locations, weather conditions, delays in obtaining permits and other government approvals, title and property access problems, geology, public opposition to infrastructure development, compliance by third parties with their contractual obligations to us and other factors. Moreover, if our infrastructure development and maintenance programs are not successfully developed on time and within budget, we may not be able to profitably fulfill our contractual obligations to third parties, including joint venture partners.
We also deliver to and are served by third-party natural gas, NGLs and oil transmission, gathering, processing and storage facilitiesbelieve that are limited in number, geographically concentrated and subject to the same risks identified above with respect to our infrastructure development and maintenance programs. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. An extended interruption of access to or service from our or third-party pipelines and facilities for any reason, including vandalism, sabotage or cyber-attacks on such pipelines and facilities or service interruptions due to gas quality, could result in adverse consequences to us, such as delays in producing and selling our natural gas, NGLs and oil. In such an event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at prices lower than we currently project. In addition, some of our third-party contracts involve significant long-term financial commitments on our part. Moreover, our usage of third parties for transmission, gathering and processing services subjects us to the performance risk of such third parties and may make us dependent upon those third parties to get our produced natural gas, NGLs and oil to market.
The substantial majority of our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating primarily in one major geographic area.
The substantial majority of our producing properties are geographically concentrated in the Appalachian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by and costs associated with governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other weather related conditions, interruption of the processing or transportation of oil, natural gas or NGLs and changes in regional and local political regimes and regulations. Such conditions could have a material adverse effect on our financial condition and results of operations.
In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations. For example, third parties may engage in subsurface mining operations near or under our properties, which could cause subsidence or other damage to our properties, adversely impact our drilling operations or adversely impact our midstream activities or those on which we rely.
Due to the concentrated nature of our portfolio of natural gas properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our future growth rate.
Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our 2018 business plan, we considered allocating capital and other resources to various aspects of our businesses, including well development, reserve acquisitions, exploratory activities, midstream infrastructure, corporate items and other alternatives. We also considered our likely sources of capital.Notwithstanding the determinations made in the development of our 2018 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify and execute optimal business strategies, including the appropriate corporate structure and appropriate rate of reserve development, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2018 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures. These transactions involve various inherent risks, such as our ability to obtain the necessary regulatory approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; the assumption of potential environmental or other liabilities; and our ability to realize the benefits expected from the transactions. In addition, various factors including prevailing market conditions could negatively impact the benefits we receive from transactions. Competition for acquisition opportunities in our industry is intense and may increase the cost of or cause us to refrain from, completing acquisitions. Joint venture arrangements may restrict our operational and corporate flexibility. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may have little control over, and our joint venture partners may not satisfy their obligationsavailable insurance is excessive relative to the joint venture. Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our earnings, cash flows and financial position.
In addition, we announced in late 2017risks presented. The occurrence of an event that our board of directors has formed a committee to evaluate options to address our sum-of-the-parts discount, with the results of such review to be announced by the end of March 2018. There can be no assurance regarding the outcome of this review or how such outcome may affect us.
Our need to comply with comprehensive, complex and sometimes unpredictable government regulations may increase our costs and limit our revenue growth, which may result in reduced earnings.
Our operations are regulated extensively at the federal, state and local levels. Laws, regulations and other legal requirements have increased the cost to plan, design, drill, install, operate and abandon wells, gathering and transmission systems and pipelines. Our exploration and production operations are subject to various types of federal, state and local laws and regulations, including regulations related to the location of wells; the method of drilling, well construction, well stimulation, hydraulic fracturing and casing design; water withdrawal and procurement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of water and other fluids and materials, including solid wastes, incidental to oil and gas
operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the plugging and abandoning of wells; the calculation, reporting and disbursement of royalties and taxes; and the gathering of production in certain circumstances. These regulations and any delays in obtaining related authorizations may affect the costs and timing of developing our natural gas resources.
Our operations are also subject to conservation and correlative rights regulations, including the regulation of the size of drilling and spacing units or field rule units; setbacks; the number of wells that may be drilled in a unit or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of natural gas properties. Some states allow the statutory pooling and unitization of tracts to facilitate development and exploration, as well as joint development of existing contiguous leases. In addition, state conservation and oil and gas laws generally limit the venting or flaring of natural gas, and may set production allowances on the amount of annual production permitted from a well.
Environmental, health and safety legal requirements govern discharges of substances into the air, ground and water; the management and disposal of hazardous substances and wastes; the clean-up of contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for drilling and pipeline construction; environmental impact studies and assessments prior to permitting; restoration of drilling properties after drilling is completed; pipeline safety (including replacement requirements); and work practices related to employee health and safety. Compliance with the laws, regulations and other legal requirements applicable to our businesses may increase our cost of doing business or result in delays due to the need to obtain additional or more detailed governmental approvals and permits. These requirements could also subject us to claims for personal injuries, property damage and other damages. Our failure to comply with the laws, regulations and other legal requirements applicable to our businesses, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.
The rates charged to customers by our gathering, transmission and storage businesses are, in many cases, subject to federal regulation by the FERC, which may prohibit us from realizing a level of return that we believe is appropriate. These restrictions may take the form of lower overall rates, imputed revenue credits, cost disallowances and/or expense deferrals. For example, under current policy, the FERC permits interstate pipelines to include an income tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines owned by partnerships, including EQM, the tax allowance reflects the actual or potential income tax liability on the FERC-jurisdictional income attributable to all partnership interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. If the FERC’s income tax allowance policy, which is subject to legal challenges, were to change and if the FERC were to disallow all or a substantial portion of the current income tax allowance for EQM’s pipelines, including adjusting the income tax allowance for reduced income tax rates enacted by the Tax Cuts and Jobs Act of 2017, EQM’s regulated rates, and therefore its revenues, could be materially adversely affected, which eventually could have a material adverse effect on our earnings and cash flows.
Certain natural gas gathering facilities are exempted from regulation by the FERC. We believe that many of our natural gas facilities meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a natural gas company, although the FERC has not made a formal determination with respect to the jurisdictional status of those facilities. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation within the industry, so the classification and regulation of some of our facilities may be subject to change based on future determinations by the FERC, the courts or the U.S. Congress.
Failure to comply with applicable provisions of the laws governing the regulation and safety of natural gas gathering, transmission and storage facilities, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.2 million per violation, per day for violations of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 or the rules, regulations, restrictions, conditions and orders promulgated under those statutes. The violation of federal pipeline safety laws could lead to the imposition of civil penalties of up to approximately $200,000 per day for each violation up to a maximum penalty of approximately $2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation.
Laws, regulations and other legal requirements are constantly changing, and implementation of compliant processes in response to such changes could be costly and time consuming. In addition to periodic changes to air, water and waste laws, as well as recent EPA initiatives to impose climate change-based air regulations on the industry, the U.S. Congress and various states have been evaluating and, in certain cases, have enacted climate-related legislation and other regulatory initiatives that would further restrict emissions of greenhouse gases, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of burning natural gas). Such restrictions may result in additional compliance obligations with respect to, or taxes on the release, capture and use of, greenhouse gases that could have an adverse effect on our operations.
Another area of regulation is hydraulic fracturing, which we utilize to complete most of our natural gas wells. Certain environmental and other groups have suggested that additional laws and regulations may be needed to more closely regulate the hydraulic fracturing process, and legislation or regulation has been proposed or is under discussion at federal, state and local levels. For instance, legislation or regulation banning hydraulic fracturing has been adopted in a number of jurisdictions in which we do not have drilling operations. We cannot predict whether any other such federal, state or local legislation or regulation will be enacted and, if enacted, how it may affect our operations, but enactment of additional laws or regulations could increase our operating costs, result in delays in production or delivery of natural gas or perhaps even preclude us from drilling wells.
Subsequent to the broad tax reform changes provided in the law known as the Tax Cuts and Job Act of 2017, other tax law changes could be enacted that have a material impact on us. The most significant potential tax law change would be a full or partial elimination of the ability to expense intangible drilling costs, or a linking of that deduction to the deduction for interest expense, either of which could adversely impact both current and deferred federal and state income tax liabilities. The cash cost of any such change could impact our ability to develop our natural gas resources.
The rates of federal, state and local taxes applicable to the industries in which we operate, including production taxes paid by EQT Production, often fluctuate, and could be increased by the various taxing authorities. In addition, the tax laws, rules and regulations that affect our business could change, such as the change resulting from the law known as the Tax Cuts and Jobs Act of 2017. Any such increase or change or varying interpretations of these laws, including the imposition of a new severance tax (a tax on the extraction of natural resources) in states in which we produce gas, could adversely impact our earnings, cash flows and financial position.
In 2010, the U.S. Congress adopted the Dodd-Frank Act which established federal oversight and regulation of the over-the-counter derivative market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation. As of the filing date of this Annual Report on Form 10-K, the CFTC had adopted and implemented many final rules that impose regulatory obligations on all market participants, including us, such as recordkeeping and certain reporting obligations. Other rules that may be relevant to us or our counterparties have yet to be finalized. Because significant rules relevant to natural gas hedging activities have not been adopted or implemented, it is not possible at this time to predict the extent of the impact of the regulations on our hedging program, including available counterparties, or regulatory compliance obligations. We have experienced increased, and anticipate additional, compliance costs and changes to current market practices as participants continue to adapt to a changing regulatory environment.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms.
We, EQM and RMP rely upon access to both short-term bank and money markets and longer-term capital markets as sources of liquidity for any capital requirements not satisfiedfully covered by the cash flows from operations or other sources. Future challenges in the global financial system, including access to capital markets and changes in the terms of and cost of capital, including increases in interest rates, may adversely affect our, EQM's or RMP's business and financial condition. Our, EQM's and RMP's ability to access the capital markets may be restricted at a time when we, EQM or RMP desire, or need, to raise capital, whichinsurance could have an impact on our, EQM's, or RMP's flexibility to react to changing economic and business conditions or our ability to implement our business strategies.
As of February 15, 2018, our Senior Notes were rated “Baa3” by Moody’s Investors Services (Moody’s), “BBB” by Standard & Poor’s Ratings Service (S&P) with a "negative" outlook, and “BBB-” by Fitch Ratings Service (Fitch), and EQM's Senior Notes were rated “Ba1” by Moody's, “BBB-” by S&P, and “BBB-” by Fitch. Although we are not aware of any current plans of Moody’s, S&P or Fitch to lower their respective ratings on our or EQM’s Senior Notes, we cannot be assured that our or EQM’s credit ratings will not be downgraded or withdrawn entirely by a rating agency. Low prices for natural gas, NGLs and oil or an increase in the level of our indebtedness in the future may result in a downgrade in the ratings that are assigned to our or EQM’s Senior Notes. If any credit rating agency downgrades the ratings, particularly below investment grade, our or EQM’s access to the capital markets may be limited, borrowing costs and margin deposits on our derivatives would increase, we may be required to provide additional credit assurances in support of pipeline capacity contracts, the amount of which may be substantial, or we or EQM may be required to provide additional credit assurances related to joint venture arrangements or construction contracts, which couldmaterially adversely affect our business, results of operations, cash flows and liquidity. Investment grade refersfinancial position.
Our drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the qualityoccurrence or timing of when they are drilled, if at all.
Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a company’s credit as assessed by one or more credit rating agencies. In order to be considered investment grade, a company must be rated “BBB-” or higher by S&P, “Baa3” or higher by Moody’s and “BBB-” or higher by Fitch.
The losssignificant part of key personnel could adversely affect our business strategy. Our ability to execute our strategic, operationaldrill and financial plans.
Our operations are dependent upon key management and technical personnel, and one or moredevelop these locations depends on a number of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on
us. In addition, the success of our operations will depend, in part, on our ability to identify, attract, develop and retain experienced personnel. There is competition within our industry for experienced technical personnel and certain other professionals, which could increase the costs associated with identifying, attracting and retaining such personnel. If we cannot identify, attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete could be harmed.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, oil spills, the explosion of natural gas transmission and gathering lines and concerns raised by advocacy groups about hydraulic fracturing and pipeline projects, may lead to increased regulatory scrutiny which may, in turn, lead to new local, state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process,uncertainties, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.
Cyber incidents may adversely impact our operations.
Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, to operate our production and midstream businesses, and the maintenance of our financial and other records has long been dependent upon such technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas, NGLs and oil difficultyprices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, topography, gathering system and pipeline transportation costs and constraints, access to and availability of water sourcing and distribution systems, coordination with coal mining, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce natural gas, NGLs or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Further, certain of the horizontal wells we intend to drill in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability. Further, as cyber incidents continuethe future may require pooling or unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to evolve,pool or unitize such leaseholds with ours, the total locations we can drill may be requiredlimited. As such, our actual drilling activities may materially differ from those presently identified.
Failure to expend additional resourcestimely develop our leased real property could result in increased capital expenditures and/or impairment of our leases.
Mineral rights are typically owned by individuals who may enter into property leases with us to continueallow for the development of natural gas. Such leases expire after an initial term, typically five years, unless certain actions are taken to modifypreserve the lease. If
we cannot preserve a lease, the lease terminates. Approximately 16% of our net undeveloped acres are subject to leases that could expire over the next three years. Lack of access to capital, changes in government regulations, changes in future development plans, reduced drilling activity, or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
Our failure to assess or capitalize on production opportunitiesthe reduction in the fair value of undeveloped properties in the areas in which we operate could negatively impact our long-term growth prospects for our production business.
Our goal of sustaining long-term growth for our production business is contingent upon our ability to identify production opportunities basedpreserve, trade, or sell our leases prior to their expiration resulting in the termination and impairment of leases for properties that we have not developed.
We evaluate capitalized costs of unproved oil and gas properties at least annually to determine recoverability on market conditions. a prospective basis. Indicators of potential impairment include changes brought about by economic factors, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. For the years ended December 31, 2020, 2019 and 2018, we recorded lease impairments and expirations of $306.7 million, $556.4 million and $279.7 million, respectively. Refer to Note 1 to the Consolidated Financial Statements.
We may incur losses as a result of title defects in the properties in which we invest.
Our decisioninability to drillcure any title defects in our leases in a well is subject to a number of factorstimely and cost-efficient manner may delay or prevent us from utilizing the associated mineral interest, which may alteradversely impact our drilling schedule or our plans to drill at all. We may have difficulty drilling all of the wells before the lease term expires which could result in the loss of certain leasehold rights, or we could drill wells in locations where we do not have the necessary infrastructure to deliver the natural gas, NGLs and oil to market. Moreover, an incorrect determination of legal title to our wells could result in liability to the owner of the natural gas or oil rights and an impairment to our assets. Successfully identifying production opportunities involves a high degree of business experience, knowledge and careful evaluation of potential opportunities, along with subjective judgments and assumptions that may prove to be incorrect. For example, seismic data is subject to interpretation and may not accurately identify the presence of natural gas or other hydrocarbons. Certain of our future drilling activities may not be successful and, if unsuccessful, this failure could adversely affect our business, results of operations or liquidity. Because we have a limited operating history in certain areas, our future operating results may be difficult to forecast, and our failure to sustain high growth ratesability in the future could adversely affect the market priceto increase production and reserves. The existence of our common stock.
Natural gas, NGLsa material title deficiency can render a lease worthless and oil price declines have resulted in impairment of certain of our non-core assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance may result in additional write-downs of the carrying amounts of our assets, including goodwill and other long lived intangible assets, which could materially andcan adversely affect our results of operations in future periods.and financial position.
We review the carrying values of our proved oil and gas properties, midstream assets and goodwill for indications of impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. In addition, we evaluate goodwill for impairment at least annually. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. The estimated future cash flows used to test our proved oil and gas properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable reserves, utilizing assumptions generally consistent with the assumptions utilized by the Company’s management for internal planning and budgeting purposes, including, among other things, the use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil, future operating costs and inflation. Commodity pricing is estimated by using a combination of the five-year
NYMEX forward strip prices and assumptions related to gas quality, basis and inflation. Proved oil and gas properties and midstream assets that have carrying amounts in excess of estimated future cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value.
Our estimate of the fair value of our assets depends on the prices of natural gas, NGLs and oil. Primarily as a result of declines in NYMEX forward strip prices, we recorded non-cash, pre-tax impairment charges of $59.7 million to certain long-lived assets during 2016 and $94.3 million to our proved oil and gas properties in the non-core Permian basin during 2015. Future declines in natural gas, NGLs or oil prices, increases in operating costs or adverse changes in well performance, among other things, may result in our having to make significant future downward adjustments to our estimated proved reserves and/or could result in additional non-cash impairment charges to write-down the carrying amount of our assets, including goodwill and other long lived intangible assets, which may have a material adverse effect on our results of operations in future periods. For example, all other things being equal, a further decline in the average five-year NYMEX forward strip price in a future period may cause the Company to recognize impairments on non-core assets, including the Company's assets in the Huron play, which had a carrying value of approximately $3 billion at December 31, 2017. Any impairment of our assets, including goodwill and other long lived intangible assets, would require us to take an immediate charge to earnings. Such charges could be material to our results of operations and could adversely impact our financial condition and results of operations. See “Impairment of Oil and Gas Properties and Goodwill” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The amount and timing of actual future natural gas, NGLs and oil production is difficult to predict and may vary significantly from our estimates, which may reduce our earnings.
OurBecause the rate of production from natural gas and oil wells, and associated NGLs, generally declines as reserves are depleted, our future success depends upon our ability to develop additional gas reserves that are economically recoverable and to optimize existing well production, and our failure to do so may reduce our earnings. Additionally, a failure to effectively and efficiently operate existing wells may cause production volumes to fall short of our projections. Our drilling and subsequent maintenance of wells can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, leases, rigs, equipment, a qualified work force, and adequate capacity for the treatment and recycling or disposal of waste water generated in our operations, as well as weather conditions, natural gas, NGLs and oil price volatility, government approvals, title and property access problems, geology, equipment failure or accidents and other factors. Drilling for natural gas NGLs and oil can be unprofitable, not only from dry wells, but from productive wells that perform below expectations or do not produce sufficient revenues to return a profit. Additionally, a failureLow natural gas, NGLs and oil prices may further limit the types of reserves that we can develop and produce economically.
Except to effectivelythe extent that we acquire additional properties containing proved reserves, conduct successful exploration and efficiently operate existing wells may causedevelopment activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Future natural gas, NGLs and oil production, volumestherefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot be certain that we will be able to fall short of our projections.find or acquire and develop additional reserves at an acceptable cost. Without continued successful development or acquisition activities, together with effectiveefficient operation of existing wells, our reserves and production, together with associated revenues, will decline as a result of our current reserves being depleted by production.
We also rely on third parties for certain construction, drilling and completion services, materials and supplies. Delays or failures to perform by such third parties could adversely impact our earnings, cash flows and financial position.
The standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated natural gas, NGLs and oil reserves.
You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas, NGLs and oil reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil, the amount, timing and cost of actual production and changes in governmental regulations or taxation. In addition, the 10% discount factor we use when calculating the standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas, NGLs and oil industry in general.
Our proved reserves are estimates that are based uponon many assumptions that may prove to be inaccurate. Any significant change in these underlying assumptions will greatly affect the quantities and present value of our reserves.
Reserve engineering is a subjective process involving estimates of underground accumulations of natural gas, NGLs and oil and assumptions concerning future prices, production levels and operating and development costs, some of which are beyond our control. These estimates and assumptions are inherently imprecise, and we may adjust our estimates of proved reserves based on changes in these estimates or assumptions. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any significant variance from our assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, NGLs and oil, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. To the extent we experience a sustained period of reduced commodity prices, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved. Although we believe our estimates are reasonable, actual production, revenues and costs to develop reserves will likely vary from estimates and these variances could be material. Numerous changes over time
to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas, NGLs and oil we ultimately recover being different from our reserve estimates.
The standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated natural gas, NGLs and crude oil reserves.
You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas, NGLs and crude oil reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil, the amount, timing and cost of actual production and changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating the standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our operations or the natural gas, NGLs and oil industry in general.
Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods.
We review the carrying values of our proved oil and gas properties for indications of impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. A significant amount of judgment is involved in performing these evaluations because the results are based on estimated future events and estimated future cash flows. The estimated future cash flows used to test our proved oil and gas properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable reserves, utilizing assumptions generally consistent with the assumptions used by our management for internal planning and budgeting purposes. Key assumptions used in our analyses, include, among other things, the intended use of the asset, the anticipated production from reserves, future market prices for natural gas, NGLs and oil, future operating costs, inflation and the anticipated proceeds that may be received upon divestiture if there is a possibility that the asset will be divested prior to the end of its useful life. Commodity pricing is estimated by using a combination of the five-year NYMEX forward strip prices and assumptions related to gas quality, locational basis adjustments and inflation. Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value.
Future declines in natural gas, NGLs or oil prices, increases in operating costs or adverse changes in well performance, among other circumstances, may result in our having to make significant future downward adjustments to our estimated proved reserves and/or could result in additional non-cash impairment charges to write-down the carrying amount of our assets, including other long-lived intangible assets, which may have a material adverse effect on our results of operations in future periods. Any impairment of our assets, including other long-lived intangible assets, would require us to take an immediate charge to earnings. Such charges could be material to our results of operations and could adversely affect our results of operations and financial position. See "Impairment of Oil and Gas Properties" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Financial and Market Risks Applicable to Our Business
Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position.
Our revenue, profitability, future rate of growth, liquidity and financial position depend upon the prices for natural gas and, to a lesser extent, NGLs and oil. The prices for natural gas, NGLs and oil have historically been volatile, and we expect this volatility to continue in the future. The prices are affected by a number of factors beyond our control, which include:
•weather conditions and seasonal trends;
•the domestic and foreign supply of and demand for natural gas, NGLs and oil;
•prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;
•national and worldwide economic and political conditions;
•new and competing exploratory finds of natural gas, NGLs and oil;
•changes in U.S. exports of natural gas, NGLs and oil;
•the effect of energy conservation efforts;
•the price, availability and acceptance of alternative fuels;
•the availability, proximity, capacity and cost of pipelines, other transportation facilities, and gathering, processing and storage facilities and other factors that result in differentials to benchmark prices;
•technological advances affecting energy consumption and production;
•the actions of the Organization of Petroleum Exporting Countries;
•the level and effect of trading in commodity futures markets, including commodity price speculators and others;
•the cost of exploring for, developing, producing and transporting natural gas, NGLs and oil;
•the level of global inventories;
•risks associated with drilling, completion and production operations; and
•domestic, local and foreign governmental regulations, tariffs and taxes, including environmental and climate change regulation.
The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.14 per MMBtu to a low of $1.33 per MMBtu from January 1, 2020 through December 31, 2020, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $63.27 per barrel to a low of $(36.98) per barrel during the same period. In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of significant increases in the supply of natural gas in the Northeast United States. Because our production and reserves predominantly consist of natural gas (approximately 93% of equivalent proved developed reserves), changes in natural gas prices have significantly greater impact on our financial results than oil prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, NGLs and oil at our ultimate sales points and thus cannot predict the ultimate impact of prices on our operations.
Prolonged low, and/or significant or extended declines in, natural gas, NGLs and oil prices may adversely affect our revenues, operating income, cash flows and financial position, particularly if we are unable to control our development costs during periods of lower natural gas, NGLs and oil prices. Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings. Reductions in cash flows from lower commodity prices may require us to incur additional borrowings or to reduce our capital spending, which could reduce our production and our reserves, negatively affecting our future rate of growth. Lower prices for natural gas, NGLs and oil may also adversely affect our credit ratings and result in a reduction in our borrowing capacity and access to other capital. See "Impairment of Oil and Gas Properties" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations." We are also exposed to the risk of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in our derivative contracts having a positive fair value in our favor. Further, adverse economic and market conditions could negatively affect the collectability of our trade receivables and cause our hedge counterparties to be unable to perform their obligations or to seek bankruptcy protection.
Increases in natural gas, NGLs and oil prices may be accompanied by or result in increased well drilling costs, increased production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels. Significant natural gas price increases may subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including swap, collar and option agreements and exchange-traded instruments), which would potentially require us to post significant amounts of cash collateral with our hedge counterparties. The cash collateral provided to our hedge counterparties, which is interest-bearing, is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related derivative contract. In addition, to the extent we have hedged our current production at prices below the current market price, we will not benefit fully from an increase in the price of natural gas.
We may not be able to successfully execute our plan to deleverage our business or otherwise reduce our debt level.
In an effort to improve our leverage ratio, in the fourth quarter of 2019, we announced a plan to reduce our absolute debt using free cash flow and targeted proceeds from the monetization of select, non-strategic exploration and production assets, core mineral assets and our remaining retained equity interest in Equitrans Midstream (the Deleveraging Plan). There can be no
assurance that we will be able to generate sufficient free cash flow or find attractive asset monetization opportunities or that any such transactions will be completed on our anticipated timeframe, if at all, which would delay or inhibit our ability to successfully execute our Deleveraging Plan. Furthermore, our estimated value for the assets to be monetized under our Deleveraging Plan involves multiple assumptions and judgments about future events that are inherently uncertain; accordingly, there can be no assurance that the resulting net cash proceeds from asset monetization transactions will be as anticipated, even if such transactions are consummated. Some of the factors that could affect our ability to successfully execute our Deleveraging Plan include changes in the financial condition or prospects of prospective purchasers and the availability of financing to potential purchasers on reasonable terms, the number of prospective purchasers, the number of competing assets on the market, unfavorable economic conditions, industry trends and changes in laws and regulations. If we are not able to successfully execute our Deleveraging Plan or otherwise reduce our absolute debt to a level we believe appropriate, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our strategic plans.
Our exploration and production operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms.
Our business is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas, NGLs and oil reserves. We typically fund our capital expenditures with existing cash and cash generated by operations and, to the extent our capital expenditures exceed our cash resources, from borrowings under our credit facility and other external sources of capital. If we do not have sufficient borrowing availability under our credit facility, we may seek alternate debt or equity financing, sell assets or reduce our capital expenditures. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
Our cash flow from operations and access to capital are subject to a number of variables, including:
•our level of proved reserves and production;
•the level of hydrocarbons we are able to produce from existing wells;
•our access to, and the cost of accessing, end markets for our production;
•the prices at which our production is sold;
•our ability to acquire, locate and produce new reserves;
•the levels of our operating expenses; and
•our ability to access the public or private capital markets or borrow under our credit facility.
If our cash flows from operations or the borrowing capacity under our credit facility are insufficient to fund our capital expenditures and we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.
As of December 31, 2020, our senior notes were rated "Ba3" with a "positive" outlook by Moody's Investors Services (Moody's), "BB" with a "stable" outlook by Standard & Poor's Ratings Service (S&P) and "BB" with a "positive" outlook by Fitch Ratings Service (Fitch). Although we are not aware of any current plans of Moody's, S&P or Fitch to downgrade its rating of our senior notes, we cannot be assured that one or more of these rating agencies will not downgrade or withdraw entirely its rating of our senior notes. Low prices for natural gas, NGLs and oil, an increase in the level of our indebtedness or a failure to significantly execute our Deleveraging Plan may result in Moody's, S&P or Fitch downgrading its rating of our senior notes. Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on the Adjustable Rate Notes (defined in Note 10 to the Consolidated Financial Statements), the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.
Risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.
As of December 31, 2020, we had approximately $4,925 million of debt outstanding, and we may incur additional indebtedness in the future. Increases in our level of indebtedness may:
•require us to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities;
•limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making certain investments, and paying dividends;
•place us at a competitive disadvantage compared to our competitors with lower debt service obligations;
•depending on the levels of our outstanding debt, limit our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes; and
•increase our vulnerability to downturns in our business or the economy, including declines in prices for natural gas, NGLs and oil.
Our debt agreements also require compliance with certain covenants. If the price that we receive for our natural gas, NGLs and oil production deteriorates from current levels or continues for an extended period, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default due to lack of covenant compliance. For more information about our debt agreements, read "Capital Resources and Liquidity" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."
We are subject to financing and interest rate exposure risks.
Our business and operating results can be adversely affected by increases in interest rates or other increases in the cost of capital resulting from a reduction in our credit rating or otherwise. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for operating and capital expenditures and place us at a competitive disadvantage.
Disruptions or volatility in the financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in the availability of credit could materially and adversely affect our ability to implement our business strategy and achieve favorable operating results. In addition, we are exposed to credit risk related to our credit facility to the extent that one or more of our lenders may be unable to provide necessary funding to us under our existing line of credit if it experiences liquidity problems.
Uncertainty related to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our current or future debt obligations.
Loans to us under our credit facility may be base rate loans or LIBOR loans. LIBOR is calculated by reference to a market for interbank lending, and it is based on increasingly fewer actual transactions. This increases the subjectivity of the LIBOR calculation process and increases the risk of manipulation. Actions by the regulators or law enforcement agencies, as well as ICE Benchmark Administration (the current administrator of LIBOR), may result in changes to the manner that LIBOR is determined or the establishment of alternative reference rates. For example, on July 27, 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. U.S. Dollar LIBOR will likely be replaced by the Secured Overnight Financing Rate (SOFR) published by the Federal Reserve Bank of New York; however, the timing of this shift is currently unknown. SOFR is an overnight rate instead of a term rate, making SOFR an inexact replacement for LIBOR, and there is not an established process to create robust, forward-looking, SOFR term rates. Changing the benchmark rate for LIBOR loans from LIBOR to SOFR requires calculations of a spread. Industry organizations are attempting to structure the spread calculation in a manner that minimizes the possibility of value transfer between counterparties, borrowers, and lenders by the transition, but there is no assurance that the calculated spread will be fair and accurate. At this time, it is not possible to predict the effect of any such changes, any establishment of alternative reference rates or any other reforms to LIBOR that may be implemented. If LIBOR ceases to exist, we may need to renegotiate our credit facility to determine the interest rate to replace LIBOR with the new standard that is established. As such, the potential effect of any such event on our interest expense cannot yet be determined.
Derivative transactions may limit our potential gains and involve other risks.
To manage our exposure to price risk, we currently and may in the future enter into derivative arrangements, utilizing commodity derivatives with respect to a portion of our future production. Such hedges are designed to lock in prices in order to limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge. In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
•our production is less than expected;
•the counterparties to our derivative contracts fail to perform on their contract obligations; or
•an event materially impacts natural gas, NGLs or oil prices or the relationship between the hedged price index and the natural gas, NGLs or oil sales price.
We cannot be certain that any derivative transaction we may enter into will adequately protect us from declines in the prices of natural gas, NGLs or oil. Furthermore, where we choose not to engage in derivative transactions in the future, we may be more adversely affected by changes in natural gas, NGLs or oil prices than our competitors who engage in derivative transactions. Lower natural gas, NGLs and oil prices may also negatively impact our ability to enter into derivative contracts at favorable prices.
Derivative transactions also expose us to a risk of financial loss if a counterparty fails to perform under a derivative contract or enters bankruptcy or encounters some other similar proceeding or liquidity constraint. In this case, we may not be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
The accounting for the Convertible Notes may have a material effect on our reported financial results.
On April 28, 2020, we issued the Convertible Notes (defined in Note 10 to the Consolidated Financial Statements) due May 1, 2026 unless earlier redeemed, repurchased or converted. In accordance with GAAP, an issuer must separately account for the liability and equity components of certain convertible debt instruments that may be settled entirely or partially in cash upon conversion in a manner that reflects the issuer's economic interest cost. The effect on the accounting for the Convertible Notes is that the equity component is required to be included in additional paid-in capital of shareholders' equity on our Condensed Consolidated Balance Sheet, and the value of the equity component is treated as a debt discount for purposes of accounting for the debt component of the Convertible Notes. Accordingly, we will be required to record a greater amount of non-cash interest expense in current and future periods as a result of the amortization of the discounted carrying value of the Convertible Notes to their face amount over the term of the Convertible Notes. We will report lower net income (or greater net loss) in our financial results because GAAP requires interest to include both the current period's amortization of the debt discount and the instrument's coupon interest, which could adversely affect our reported or future financial results, the market price of our common stock and the trading price of the Convertible Notes.
In addition, because we have the ability and intent to settle the Convertible Notes, upon conversion, by paying or delivering cash equal to the principal amount of the obligation and common stock for amounts over the principal amount, the shares issuable upon conversion of the Convertible Notes are accounted for using the treasury stock method and, as such, are not included in the calculation of diluted earnings per share except to the extent that the conversion value of the Convertible Notes exceeds their principal amount. Further, under the treasury stock method, the transaction is accounted for as if the number of shares of common stock that would be necessary to settle such excess are issued. We cannot be sure that we will be able to continue to demonstrate the ability or intent to settle in cash or that the accounting standards will continue to permit the use of the treasury stock method. If we are unable to use the treasury stock method in accounting for the shares issuable upon conversion of the Convertible Notes, our diluted earnings per share could be adversely affected.
Risks Associated with Our Human Capital, Technology and Other Resources and Service Providers
Strategic determinations, including the allocation of resources to strategic opportunities, are challenging, and our failure to appropriately allocate resources among our strategic opportunities may adversely affect our financial position and reduce our future prospects.
Our future prospects are dependent upon our ability to identify optimal strategies for our business. Our operational strategy focuses on developing several multi-well pads in tandem through a process known as combo-development. We have allocated a
substantial portion of our financial, human capital and other resources to pursuing this strategy, including investing in new technologies and equipment, restructuring our workforce, and pursuing various ESG initiatives geared towards enhancing our strategy. We may not realize some or any of the anticipated strategic, financial, operational, environmental and other anticipated benefits from our operational strategy and the corresponding investments we have made in pursuing our strategy. Additionally, we cannot be certain that we will be able to successfully execute combo-development projects at the pace and scale that we project, which may delay or reduce our production and our reserves, negatively affecting our associated revenues. If we fail to identify and successfully execute optimal business strategies, including the appropriate operational strategy and corresponding initiatives, or fail to optimize our capital investments and the use of our other resources in furtherance of optimal business strategies, our financial position and growth may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
Cyber incidents targeting our digital work environment or other technologies or natural gas and oil industry systems and infrastructure may adversely impact our operations.
Our business and the natural gas and oil industry in general have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, and the maintenance of our financial and other records has long been dependent upon such technologies. We depend on this technology to record and store data, estimate quantities of natural gas, NGLs and oil reserves, analyze and share operating data and communicate internally and externally. Computers and mobile devices control nearly all of the natural gas, NGLs and oil distribution systems in the U.S., which are necessary to transport our products to market.
The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. We can provide no assurance that we will not suffer such attacks in the future. Deliberate attacks on, or unintentional events affecting, our digital work environment or other technologies and infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas, NGLs and oil, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability. Further, as cyber incidents continue to evolve and cyber attackers become more sophisticated, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. The cost to remedy an unintended dissemination of sensitive information or data may be significant. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.
The unavailability or high cost of additional drilling rigs, completion services, equipment, supplies, personnel, and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages or higher costs. Historically, there have been shortages of personnel and equipment as demand for personnel and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could materially adversely affect our business, results of operations, cash flows and financial position.
Our ability to drill for and produce natural gas is dependent on the availability of adequate supplies of water for drilling and completion operations and access to water and waste disposal or recycling services at a reasonable cost and in accordance with applicable environmental rules. Restrictions on our ability to obtain water or dispose of produced water and other waste may adversely affect our results of operations, cash flows and financial position.
The hydraulic fracture stimulation process on which we depend to drill and complete natural gas wells requires the use and disposal of significant quantities of water. Our ability to access sources of water and the availability of disposal alternatives to receive all of the water produced from our wells and used in hydraulic fracturing may affect our drilling and completion operations. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, or to timely obtain water sourcing permits or other rights, could adversely affect our operations. Additionally, the imposition of new
environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste, which would adversely affect our business and results of operations, which could result in decreased cash flows.
In addition, federal and state regulatory agencies recently have focused on a possible connection between the operation of injection wells used for natural gas and oil waste disposal and increased seismic activity in certain areas. In some cases, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Increased regulation and attention given to induced seismicity in the states where we operate could lead to restrictions on our disposal well injection volumes and increased scrutiny of and delay in obtaining new disposal well permits, which could result in increased operating costs, which could be material, or a curtailment of our operations.
The loss of key personnel could adversely affect our ability to execute our strategic, operational and financial plans.
Our operations are dependent upon key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, the success of our operations will depend, in part, on our ability to identify, attract, develop and retain experienced personnel. There is competition within our industry for experienced technical personnel and certain other professionals, which could increase the costs associated with identifying, attracting and retaining such personnel. If we cannot identify, attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete in our industry could be harmed.
We depend on third-party midstream providers for a significant portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure to successfully deliver natural gas, NGLs and oil to market on competitive terms may adversely affect our earnings, cash flows and results of operations.
Our delivery of natural gas, NGLs and oil depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and processing facilities primarily owned by third parties, and our ability to contract with these third parties at competitive rates or at all. The capacity of transmission, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our natural gas, NGLs and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Competition for access to pipeline infrastructure within the Appalachian Basin is intense, and our ability to secure access to pipeline infrastructure on favorable economic terms could affect our competitive position.
We are dependent on third-party providers to provide us with access to midstream infrastructure to get our produced natural gas, NGLs and oil to market. To the extent these services are delayed or unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Access to midstream assets may be unavailable due to market conditions or mechanical or other reasons. In addition, at current commodity prices, construction of new pipelines and building of such infrastructure may occur more slowly. A lack of access to needed infrastructure, or an extended interruption of access to or service from third-party pipelines and facilities for any reason, including vandalism, terroristic acts, sabotage or cyber-attacks on such pipelines and facilities or service interruptions due to gas quality, could result in adverse consequences to us, such as delays in producing and selling our natural gas, NGLs and oil.
Finally, in order to ensure access to certain midstream facilities, we have entered into agreements that obligate us to pay demand charges to various pipeline operators. We also have commitments with third parties for processing capacity. We may be obligated to make payments under these agreements even if we do not fully use the capacity we have reserved, and these payments may be significant.
The substantial majority of our midstream and water services are provided by one provider, EQM Midstream Partners LP (EQM), a wholly-owned subsidiary of Equitrans Midstream. Therefore, any regulatory, infrastructure, or other events that materially adversely affect EQM's business operations will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers. Additionally, our midstream services contracts with EQM involve significant long-term financial and other commitments on our part, which hinders our ability to diversify our slate of midstream service providers and seek better economic and other terms for the midstream services that are provided to us. We have no control over Equitrans Midstream's or EQM's business decisions and operations, and neither Equitrans Midstream nor EQM is under any obligation to adopt a business strategy that favors us.
Historically, we have received the substantial majority of our natural gas gathering, transmission and storage and water services from EQM. Additionally, on February 26, 2020, we executed a new gas gathering agreement with EQM (the Consolidated
GGA), which, among other things, consolidated the majority of our prior gathering agreements with EQM into a single agreement, established a new fee structure for gathering and compression fees charged by EQM, increased our minimum volume commitments with EQM, committed certain of our remaining undedicated acreage to EQM and extended our and EQM's contractual obligations with each other to 2035. Because we have significant long-term contractual commitments with EQM, we expect to receive the majority of our midstream and water services from EQM for the foreseeable future. Therefore, any event, whether in our areas of operation or otherwise, that adversely affects EQM's operations, water assets, pipelines, other transportation facilities, gathering and processing facilities, financial condition, leverage, results of operations or cash flows will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers. Accordingly, we are subject to the business risks of EQM, including the following:
•federal, state and local regulatory, political and legal actions that could adversely affect EQM's operations, assets and infrastructure, including potential further delays associated with obtaining regulatory approval for the construction of the Mountain Valley Pipeline and the MVP Southgate project;
•construction risks associated with the construction or repair of EQM's pipelines and other midstream infrastructure, such as delays caused by landowners or advocacy groups opposed to the natural gas industry, environmental hazards, adverse weather conditions, the performance of third-party contractors, the lack of available skilled labor, equipment and materials and the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights-of-way, approvals and permits once obtained);
•acts of cybersecurity, sabotage or terrorism that could cause significant damage or injury to EQM's personnel, assets or infrastructure or lead to extended interruptions of EQM's operations;
•risks associated with EQM failing to properly balance supply and demand for its services, on a short-term, seasonal and long-term basis, which could result in EQM being unable to provide its customers, including us, with sufficient access to pipeline and other midstream infrastructure and water services as needed; and
•risks associated with EQM's leverage and financial profile, which could result in EQM being financially deterred or prohibited from providing services to its customers, including us, on a timely basis or at all.
In addition, many of our midstream services obligations with EQM are "firm" commitments, under which we have reserved an agreed upon amount of pipeline or storage capacity with EQM regardless of the capacity that we actually use during each month, and we are generally obligated to pay a fixed, monthly charge, at an amount agreed upon in the contract. Because these obligations involve significant long-term financial and other commitments on our part, they could reduce our cash flow during periods of low prices for natural gas, NGLs and oil when we may have lower volumes of natural gas and NGLs and therefore less of a need for capacity and storage, or the market prices for such pipeline and storage capacity services may be lower than what we are contractually obligated to pay to EQM.
Further, the Consolidated GGA provides for a reduced fee structure for the gathering and compression fees charged by EQM; however this new fee structure does not take effect until the Mountain Valley Pipeline's in-service date. There can be no assurance that the in-service date of the Mountain Valley Pipeline will not be delayed, or that the project will not be cancelled entirely, which would consequently delay, possibly indefinitely, the effective date of the fee reductions contemplated in the Consolidated GGA. Neither Equitrans Midstream nor EQM is under any obligation to renegotiate their contracts with us, including the Consolidated GGA, in the event of a prolonged depressed commodity price environment or if the Mountain Valley Pipeline's in-service date is delayed. We have recorded in our Consolidated Balance Sheet a contract asset of $410 million representing the estimated fair value of the rate relief provided by the Consolidated GGA that would be realized beginning with the Mountain Valley Pipeline’s in-service date. We review the contract asset for indications of impairment when events or circumstances indicate the carrying value may not be recoverable. Although the Consolidated GGA provides a cash payment option that grants us the right to receive payments from EQM in the event that the Mountain Valley Pipeline in-service date has not occurred prior to January 1, 2022, future delays in the Mountain Valley Pipeline’s in-service date may nonetheless affect our ability to fully realize the value we recorded as a contract asset for the rate relief associated with the Consolidated GGA, which could adversely affect our results of operations in future periods.
Substantially all of our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating primarily in one major geographic area.
Substantially all of our producing properties are geographically concentrated in the Appalachian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by, and costs associated with, governmental regulation, state and local political activities, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other weather-related conditions, interruption of the processing or transportation of natural gas,
NGLs or oil and changes in state and local laws, judicial precedents, political regimes and regulations. Such conditions could materially adversely affect our results of operations and financial position.
In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations. For example, third parties may engage in subsurface coal and other mining operations near or under our properties, which could cause subsidence or other damage to our properties, adversely impact our drilling operations or adversely impact third-party midstream activities on which we rely. In such event, our operations may be impaired or interrupted, and we may not be able to recover the costs incurred as a result of temporary shut-ins or the plugging and abandonment of any of our wells. Furthermore, the existence of mining operations near our properties could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. These restrictions on our operations, and any similar restrictions, could cause delays or interruptions or prevent us from executing our business strategy, which could materially adversely affect our results of operations and financial position.
Further, insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices. The Appalachian Basin has experienced periods in which production has surpassed local takeaway capacity, resulting in substantial discounts in the price received by producers such as us and others at times being possibly shut in. Although additional Appalachian Basin takeaway capacity has been added in recent years, the existing and expected capacity may not be sufficient to keep pace with the increased production caused by accelerated drilling in the area in the short term.
Due to the concentrated nature of our portfolio of natural gas properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.
Legal and Regulatory Risks
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Opposition toward oil and natural gas drilling and development activities generally has been growing globally and is particularly pronounced in the U.S., and companies in our industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability and business practices. Negative public perception regarding us and/or our industry may lead to increased litigation and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new local, state and federal laws, regulations, guidelines and enforcement interpretations in safety, environmental, royalty and surface use areas. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, challenged or burdened by requirements that restrict our ability to profitably conduct our business. In addition, anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations, such as drilling and development. If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition and results of operations.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our exploration and production operations are subject to various types of federal, state and local laws and regulations, including regulations related to the location of wells; the method of drilling, well construction, well stimulation, hydraulic fracturing and casing design; water withdrawal and procurement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of water and other fluids and materials, including solid and hazardous wastes, incidental to natural gas and oil operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the plugging and abandoning of wells; the calculation, reporting and disbursement of royalties and taxes; and the gathering of production in certain circumstances.
Our operations are also subject to conservation and correlative rights regulations, including the regulation of the size of drilling and spacing units or field rule units; setbacks; the number of wells that may be drilled in a unit or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of properties. Some states allow the statutory pooling and unitization of tracts to facilitate development and exploration, as well as joint
development of existing contiguous leases. In addition, state conservation and natural gas and oil laws generally limit the venting or flaring of natural gas and may set production allowances on the amount of annual production permitted from a well.
Environmental, health and safety legal requirements govern discharges of substances into the air, ground and water; the management and disposal of hazardous substances and wastes; the clean-up of contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for drilling; environmental impact studies and assessments prior to permitting; restoration of drilling properties after drilling is completed; and work practices related to employee health and safety.
To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Maintaining compliance with the laws, regulations and other legal requirements applicable to our business and any delays in obtaining related authorizations may affect the costs and timing of developing our natural gas, NGLs and oil resources. These requirements could also subject us to claims for personal injuries, property damage and other damages. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could materially adversely affect our results of operations, cash flows and financial position. Our failure to comply with the laws, regulations and other legal requirements applicable to our business, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages as well as corrective action costs.
Changes in tax laws and regulations could adversely impact our earnings and the cost, manner or feasibility of conducting our operations.
Effective January 1, 2018, changes to certain U.S. federal income tax laws were signed into law that impact us, including but not limited to: changes to the regular income tax rate; the elimination of the alternative minimum tax (AMT); full expensing of capital equipment; limited deductibility of interest expense; and increased limitations on deductible executive compensation. On March 27, 2020, the U.S. Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (CARES Act), which, among other things, includes provisions relating to net operating loss (NOL) carryback periods, AMT credit refunds and modifications to the net interest deduction limitations. In particular, under the CARES Act, (i) for taxable years beginning before 2021, NOL carryforwards and carrybacks may offset 100% of taxable income, (ii) NOLs arising in 2018, 2019, and 2020 taxable years may be carried back to each of the preceding five years to generate a refund, and (iii) for taxable years beginning in 2019 and 2020, the base for interest deductibility is increased from 30% to 50% of EBITDA.
Members of Congress periodically introduce legislation to revise U.S. federal income tax laws which could have a material impact on us. The most significant potential tax law changes that could impact us include increases in the regular income tax rate, a new minimum tax based on net income, the expensing of intangible drilling costs or percentage depletion, the repeal of like-kind exchange tax deferral rules on real property and further limited deductibility of interest expense, any of which could adversely impact our current and deferred federal and state income tax liabilities. State and local taxing authorities in jurisdictions in which we operate or own assets may enact new taxes, such as the imposition of a severance tax on the extraction of natural resources in states in which we produce natural gas, NGLs and oil, or change the rates of existing taxes, which could adversely impact our earnings, cash flows and financial position.
Our hedging activities are subject to numerous and evolving financial laws and regulations which could inhibit our ability to effectively hedge our production against commodity price risk or increase our cost of compliance.
We use financial derivative instruments to hedge the impact of fluctuations in natural gas, NGLs and oil prices on our results of operations and cash flows. In 2010, Congress adopted the Dodd-Frank Act, which established federal oversight and regulation of the OTC derivative market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC, the SEC and certain federal agencies that regulate the banking and insurance sectors (Prudential Regulators) to promulgate rules and regulations implementing the legislation. Among other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivative activities. Although some of the rules necessary to implement the Dodd-Frank Act have yet to be adopted, the CFTC, the SEC and Prudential Regulators have issued numerous rules, including the End-User Exception, which exempts certain “end-users” from having to comply with mandatory clearing, a Margin Rule mandating margining for certain uncleared swaps, and a Position Limits Rule imposing federal position limits on certain futures contracts relating to energy products, including natural gas.
We qualify as a “non-financial entity” for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing, although we are subject to certain recordkeeping and reporting obligations associated with such rule. We also qualify as a “non-financial end user” for purposes of the Margin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, although the Position Limits Rule does not go into effect with respect to energy products until January 1, 2022, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under the Position Limits Rule and will not be subject to the limitations under such rule. However, many of our hedge counterparties and other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule, which may affect the pricing and/or availability of derivatives for us. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which apply to our transactions with counterparties subject to such Foreign Regulations.
The Dodd-Frank Act, the rules adopted thereunder and the Foreign Regulations could increase the cost of our derivative contracts, alter the terms of our derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or the Foreign Regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements. Any of these consequences could have a material and adverse effect on our business, financial position and results of operations. We have experienced increased, and anticipate additional, compliance costs and changes to current market practices as participants continue to adapt to a changing financial regulatory environment.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing and governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of natural gas and oil wells, which could adversely affect our production.
We use hydraulic fracturing in the completion of our wells. Hydraulic fracturing typically is regulated by state natural gas and oil commissions, but the EPA has asserted federal regulatory authority. For example, the EPA finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules.
Certain governmental reviews have been conducted or are underway that focus on the environmental aspects of hydraulic fracturing practices. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from constructing wells. See "Business-Regulation-Environmental, Health and Safety Regulation" for more information.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.
We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment and occupational health and workplace safety, including regulations and enforcement policies that have tended to become increasingly strict over time resulting in longer waiting periods to receive permits and other regulatory approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.
Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those
actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and occupational health and workplace safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters.
In addition, new or additional laws and regulations, new interpretations of existing requirements or changes in enforcement policies could impose unforeseen liabilities, significantly increase compliance costs or result in delays of, or denial of rights to conduct, our development programs. For example, in June 2015, the EPA and the Corps issued a final rule under the CWA defining the scope of the EPA's and the Corps' jurisdiction over WOTUS, which was stayed nationwide in October 2015 pending resolution of several legal challenges. The EPA and the Corps proposed a rule in July 2017 to repeal the WOTUS rule and announced their intent to issue a new rule defining the CWA's jurisdiction. In January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction to hear challenges to the WOTUS rule resides with the federal district courts, which lifted the stay and resulted in a patchwork application of the rule in some states, but not in others. In October 2019, the EPA issued a final rule repealing the WOTUS rule and the repeal rule became effective in December 2019. In April 2020, the EPA and the Corps published the NWPR, which narrows the definition of WOTUS to four categories of jurisdictional waters and includes twelve categories of exclusions, including groundwater. A coalition of states and cities, environmental groups, and agricultural groups have challenged the NWPR and a federal district court in Colorado stayed implementation of the rule. The stay is limited to application of the rule in Colorado; the rule has taken effect in all other states. In addition, in an April 2020 decision defining the scope of the CWA that was handed down just days after the NWPR was published, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. The Court rejected the EPA and Corps’ assertion that groundwater should be totally excluded from the CWA. The Court’s decision is expected to bolster challenges to the NWPR. On January 20, 2021, the Biden Administration announced it will review the NWPR in accordance with the January 20, 2021 Executive Order that revokes President Trump’s Executive Order 13778, which required review and reversal of the WOTUS rule. The EPA and the Corps have requested to stay the litigation over the NWPR during the agencies’ review of the rule. To the extent a rule expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Such potential regulations or litigation could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which in turn could materially adversely affect our results of operations and financial position. Further, the discharges of natural gas, NGLs, oil, and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties.
Regulations related to the protection of wildlife could adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Our operations can be adversely affected by regulations designed to protect various wildlife. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in constraints on our exploration and production activities. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Fuel conservation measures, consumer tastes and technological advances could reduce demand for natural gas and oil.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas and oil. The impact of the changing demand for natural gas and oil could adversely impact our earnings, cash flows and financial position.
Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the natural gas, NGLs and oil that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring
and reporting of GHG emissions from specified onshore and offshore natural gas and oil production sources in the United States on an annual basis, which include certain of our operations. At the state level, several states including Pennsylvania have proceeded with regulation targeting GHG emissions. Such state regulations could impose increased compliance costs on our operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of federal legislation in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In October 2019, Pennsylvania Governor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join the RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In September 2020, the Pennsylvania Environmental Quality Board approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020. Based on the current timeline for implementation, final rulemaking is expected to be sent to the Pennsylvania Environmental Quality Board for review and approval in the fourth quarter of 2021, with the first year of compliance anticipated to begin in 2022. Assuming Pennsylvania ultimately becomes a member of the RGGI in 2022, as currently anticipated, it will result in increased operating costs if we are required to purchase emission allowances in connection with our operations.
On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does not impose any binding obligations on its participants. In August 2017, the U.S. Department of State officially informed the United Nations of the United States' intent to withdraw from the Paris Agreement, with such withdrawal becoming effective in November 2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which will become effective in 30 days from such date.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the natural gas, NGLs and oil we produce and lower the value of our reserves.
Further, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.
Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations. See "Business-Regulation-Environmental, Health and Safety Regulation" for more information.
Risks Associated with Strategic Transactions
Entering into strategic transactions may expose us to various risks.
We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures. These transactions involve various inherent risks, such as our ability to obtain the necessary regulatory and third-party approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; the assumption of potential environmental or other liabilities; and our ability to realize the benefits expected from the transactions. In addition, various factors, including prevailing market conditions, could negatively impact the benefits we receive from these transactions. Competition for transaction opportunities in our industry is intense and may increase the cost of, or cause us to refrain from, completing transactions. Joint venture arrangements may restrict our operational and corporate flexibility.
Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may have little or partial control over, and our joint venture partners may not satisfy their obligations to the joint venture. Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our earnings, cash flows and financial position.
Acquisitions may disrupt our current plans or operations and may not be worth what we pay due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.
Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration potential, future natural gas, NGLs and oil prices, operating costs, production taxes and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well or lease that we acquire, and even when we inspect a well or lease we may not discover structural, subsurface, or environmental problems that may exist or arise.
There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an "as is" basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.
The Separation and Distribution may subject us to future liabilities.
In November 2018, we completed the Separation and Distribution (each defined and discussed in Note 8 to the Consolidated Financial Statements), resulting in the spin-off of Equitrans Midstream, a standalone publicly traded corporation that holds our former midstream business.
Pursuant to agreements we entered into with Equitrans Midstream in connection with the Separation, we and Equitrans Midstream are each generally responsible for the obligations and liabilities related to our respective businesses. Pursuant to those agreements, we and Equitrans Midstream each agreed to cross-indemnities principally designed to allocate financial responsibility for the obligations and liabilities of our business to us and those of Equitrans Midstream's business to it. However, third parties, including governmental agencies, could seek to hold us responsible for obligations and liabilities that Equitrans Midstream agreed to retain or assume, and there can be no assurance that the indemnification from Equitrans Midstream will be sufficient to protect us against the full amount of such obligations and liabilities, or that Equitrans Midstream will be able to fully satisfy its indemnification obligations. Additionally, if a court were to determine that the Separation or related transactions were consummated with the actual intent to hinder, delay or defraud current or future creditors or resulted in Equitrans Midstream receiving less than reasonably equivalent value when it was insolvent, or that it was rendered insolvent, inadequately capitalized or unable to pay its debts as they become due, then it is possible that the court could disregard the allocation of obligations and liabilities agreed to between us and Equitrans Midstream, impose substantial obligations and liabilities on us and void some or all of the Separation-related transactions. Any of the foregoing could adversely affect our results of operations and financial position.
If there is a later determination that the Distribution or certain related transactions are taxable for U.S. federal income tax purposes because the facts, assumptions, representations or undertakings underlying the IRS private letter ruling and/or opinion of counsel are incorrect or for any other reason, significant liabilities could be incurred by us, our shareholders or Equitrans Midstream.
In connection with the Separation and Distribution, we obtained a private letter ruling from the IRS and an opinion of outside counsel regarding the qualification of the Distribution, together with certain related transactions, as a transaction that is generally tax-free, for U.S. federal income tax purposes, under Sections 355 and 368(a)(1)(D) of the U.S. Internal Revenue Code, as amended, and certain other U.S. federal income tax matters relating to the Distribution and certain related transactions. The IRS private letter ruling and the opinion of counsel are based on and rely on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of us and Equitrans Midstream, including those relating to the past and future conduct of us and Equitrans Midstream. If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if we or Equitrans Midstream breach any representations or covenants contained in any of the Separation-related agreements and documents or in any documents relating to the IRS private letter
ruling and/or the opinion of counsel, we and our shareholders may not be able to rely on the IRS private letter ruling or the opinion of counsel.
Notwithstanding receipt of the IRS private letter ruling and the opinion of counsel, the IRS could determine on audit that the Distribution and/or certain related transactions should be treated as taxable transactions for U.S. federal income tax purposes if it determines that any of the representations, assumptions or undertakings upon which the IRS private letter ruling was based are false or have been violated or if it disagrees with the conclusions in the opinion of counsel that are not covered by the ruling or for other reasons. An opinion of counsel represents the judgment of such counsel and is not binding on the IRS or any court, and the IRS or a court may disagree with the conclusions in such opinion of counsel. Accordingly, notwithstanding receipt of the IRS private letter ruling and the opinion of counsel, there can be no assurance that the IRS will not assert that the Distribution and/or certain related transactions should be treated as taxable transactions or that a court would not sustain such a challenge. In the event the IRS were to prevail with such challenge, we, Equitrans Midstream and our shareholders could be subject to material U.S. federal and state income tax liabilities. In connection with the Separation, we and Equitrans Midstream entered into a tax matters agreement, which described the sharing of any such liabilities between us and Equitrans Midstream.
We are a significant shareholder of Equitrans Midstream and the value of our investment in Equitrans Midstream may fluctuate substantially.
Following the Separation and Distribution, we retained approximately 19.9% of the outstanding shares of Equitrans Midstream's common stock. On February 26, 2020, we entered into share purchase agreements with Equitrans Midstream to sell approximately 50% of our equity interest in Equitrans Midstream to Equitrans Midstream (the Equitrans Share Exchange) in exchange for a combination of cash and fee relief under our gathering agreements with EQM. We currently own 25,296,026 shares of Equitrans Midstream's common stock. The value of our investment in Equitrans Midstream may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the midstream industry, including loss of gathering and transportation volumes, the effect of laws and regulations on the operation of its business and development of its assets, increased competition, loss of contracted volumes, adverse rate-making decisions, policies and rulings by the FERC, pipeline safety rulemakings initiated or finalized by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration, delays in the timing of, or the failure to complete, expansion projects, lack of access to capital and operating risks and hazards.
We intend to dispose of our remaining interest in Equitrans Midstream through one or more divestitures of our shares of Equitrans Midstream's common stock. However, we can offer no assurance that we will be able to complete such disposition or as to the value we will realize. The occurrence of any of these and other risks faced by Equitrans Midstream could adversely affect the value of our investment in Equitrans Midstream.
Risks Related to the COVID-19 Pandemic
The novel coronavirus, or COVID-19, pandemic has affected and may materially adversely affect, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our operations, financial performance and condition, operating results and cash flows.
The COVID-19 pandemic has affected, and may materially adversely affect, our business and financial and operating results. The severity, magnitude and duration of the COVID-19 pandemic is uncertain, rapidly changing and hard to predict. In 2020, the pandemic significantly impacted economic activity and markets around the world, and, in the future, COVID-19 or another similar pandemic could negatively impact our business in numerous ways, including, but not limited to, the following:
•our revenue may be reduced if the pandemic results in an economic downturn or recession that leads to a prolonged decrease in the demand for natural gas and, to a lesser extent, NGLs and oil;
•our operations may be disrupted or impaired (thus lowering our production level), if a significant portion of our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the pandemic;
•the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, NGLs and oil, may be disrupted or suspended in response to containing the pandemic, and/or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices
we receive for our produced natural gas, NGLs and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties; and
•the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to raise capital or find attractive asset monetization opportunities and successfully execute our Deleveraging Plan within our anticipated timeframe or at all.
We believe that our principal areas of operational risk resulting from a pandemic are availability of service providers and supply chain disruption. Active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of personnel and contractors on site. While we believe that we are following best practices under COVID-19 guidance, the potential for transmission still exists. In certain instances, it may be necessary or determined advisable for us to delay development operations.
To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth herein, such as those relating to our financial performance, our ability to access capital and credit markets, our credit ratings and debt obligations. The rapid development and fluidity of this situation precludes any prediction as to the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments that we are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, NGLs and oil, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic.
See Item 7A, “Quantitative7A., "Quantitative and Qualitative Disclosures About Market Risk,”Risk" for further discussion regarding the Company’sof our exposure to market risks, including the risks associated with the Company'sour use of derivative contracts to hedge commodity prices.
Item 1B.Unresolved Staff Comments
None.
Item 2.Properties
Principal facilities are owned or, in the case of certain office locations, warehouse buildings and equipment, leased, by the Company’s business segments. The majority of the Company’s properties are located on or under (i) private properties owned in fee, held by lease or occupied under perpetual easements or other rights acquired for the most part without warranty of underlying land titles or (ii) public highways under franchises or permits from various governmental authorities. The Company’s facilities are generally well maintained and, where appropriate, are replaced or expanded to meet operating requirements.
EQT Production: EQT Production’s properties are located primarily in Pennsylvania, West Virginia, Ohio, Kentucky and Virginia. This segment has approximately 4.0 million gross acres (approximately 72% of which are considered undeveloped)See Item 1., which encompass substantially all of the Company’s acreage of proved developed and undeveloped natural gas and oil producing properties. Of these gross acres, approximately 1.1 million are in the Marcellus play, many of which have associated deep Utica or Upper Devonian drilling rights, and approximately 0.1 million are in the Ohio Utica. Although most of its wells are drilled to relatively shallow depths (2,000 to 8,000 feet below the surface), the Company retains what are normally considered “deep rights” on the majority of its acreage. As of December 31, 2017, the Company estimated its total proved reserves to be 21.4 Tcfe, consisting of proved developed producing reserves of 11.1 Tcfe, proved developed non-producing reserves of 0.2 Tcfe and proved undeveloped reserves of 10.1 Tcfe. Substantially all of the Company’s reserves reside in continuous accumulations.
The Company’s estimate of proved natural gas, NGLs and oil reserves is prepared by Company engineers. The engineer primarily responsible for preparing the reserve report and the technical aspects of the reserves audit received a bachelor’s degree
in Petroleum and Natural Gas Engineering from The Pennsylvania State University and has 29 years of experience in the oil and gas industry. To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves. Additionally, division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems, and the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management.
The Company’s estimate of proved natural gas, NGLs and oil reserves is audited by the independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott), which is hired by the Company’s management. Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. In the course of its audit, Ryder Scott reviewed 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company’s interests as of December 31, 2017. Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 81% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining approximately 19% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 256 wells per case for non-operated wells. For undeveloped locations, the Company determined, and Ryder Scott reviewed and approved, the areas within the Company’s acreage considered to be proven. For undeveloped locations, reserves were assigned and projected by the Company’s reserves engineers for locations within these proven areas and approved by Ryder Scott based on analogous type curves and offset production information. Ryder Scott’s audit report has been filed herewith as Exhibit 99.
No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company’s estimated total reserves. Additional information relating to the Company’s estimates of natural gas, NGLs and crude oil reserves and future net cash flows is provided in Note 23 (unaudited) to the Consolidated Financial Statements.
In 2017, the Company commenced drilling operations (spud or drilled) on 144 gross horizontal Marcellus wells, 49 gross horizontal Upper Devonian wells, seven gross horizontal Ohio Utica wells and one other gross well. Total proved reserves in the Marcellus play increased 51% to 16.9 Tcfe in 2017 primarily as a result of the Company’s acquisition and drilling activity. Production sales volumes in 2017 from the Marcellus, including the Upper Devonian play, was 770.6 Bcfe. Over the past five years, the Company has experienced a 97% developmental drilling success rate.
Natural gas, NGLs and crude oil pricing:
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| Natural Gas: | | |
| | |
| | |
|
| Average sales price (excluding cash settled derivatives) ($/Mcf) | | $ | 2.82 |
| | $ | 1.88 |
| | $ | 2.28 |
|
| Average sales price (including cash settled derivatives) ($/Mcf) | | $ | 2.89 |
| | $ | 2.41 |
| | $ | 3.06 |
|
| NGLs (excluding ethane): | | | | |
| | |
|
| Average sales price (excluding cash settled derivatives) ($/Bbl) | | $ | 31.59 |
| | $ | 19.43 |
| | $ | 18.84 |
|
| Average sales price (including cash settled derivatives) ($/Bbl) | | $ | 30.90 |
| | $ | 19.43 |
| | $ | 18.84 |
|
| Ethane: | | | | | | |
| Average sales price ($/Bbl) (a) | | $ | 6.32 |
| | $ | 5.08 |
| | $ | — |
|
| Crude Oil: | | | | |
| | |
|
| Average sales price ($/Bbl) | | $ | 40.70 |
| | $ | 34.73 |
| | $ | 38.70 |
|
(a) Ethane sales began in 2016.
For additional information on pricing, see “Consolidated Operational Data” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The Company’s average per unit production cost, excluding production taxes, of natural gas, NGLs and oil during 2017, 2016 and 2015 was $0.13 per Mcfe, $0.15 per Mcfe and $0.19 per Mcfe, respectively. At December 31, 2017, the Company had approximately 50 multiple completion wells.
|
| | | | |
| | | Natural Gas | | Oil |
| Total productive wells at December 31, 2017: | | | | |
| Total gross productive wells | | 14,498 | | 108 |
| Total net productive wells | | 13,596 | | 104 |
| Total in-process wells at December 31, 2017: | | 0 | | |
| Total gross in-process wells | | 413 | | — |
| Total net in-process wells | | 368 | | — |
Summary of proved natural gas, oil and NGL reserves as of December 31, 2017 based on average fiscal year prices:
|
| | | | |
| | | Natural Gas (MMcf) | | Oil and NGLs (Bbls) |
| Developed | | 10,152,543 | | 190,901 |
| Undeveloped | | 9,677,693 | | 78,337 |
| Total proved reserves | | 19,830,236 | | 269,238 |
|
| |
Total acreage at December 31, 2017: | |
Total gross productive acres | 1,126,606 |
Total net productive acres | 1,058,833 |
Total gross undeveloped acres | 2,872,468 |
Total net undeveloped acres | 2,586,586 |
As of December 31, 2017, the Company had no proved undeveloped reserves that had remained undeveloped for more than five years.
As of December 31, 2017, leases associated with approximately 92,000 gross undeveloped acres expire in 2018 if they are not renewed. The Company has an active lease renewal program in areas targeted for development. Within the Marcellus formation, the Company must drill one well in 2018 under a lease and acquisition agreement or 139 net acres will be at-risk.
Number of net productive and dry exploratory and development wells drilled:
|
| | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| Exploratory wells: | | |
| | |
| | |
|
| Productive | | — |
| | — |
| | 1.0 |
|
| Dry | | 1.0 |
| | — |
| | 1.0 |
|
| Development wells: | | | | |
| | |
|
| Productive | | 149.2 |
| | 140.9 |
| | 234.5 |
|
| Dry | | 4.9 |
| | 15.0 |
| | 3.0 |
|
The increase in dry developmental wells in 2016 was primarily related to vertical wells that are no longer planned to be drilled horizontally due to the uncertainty of identifying a near-term pipeline solution.
The table below provides select production, sales and acreage data by state (as of December 31, 2017 unless otherwise noted), which is substantially all from the Appalachian Basin. NGLs and oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods. Refer to the table on page 38 for sales volumes by final product.
|
| | | | | | | | | | | | | | | | | | |
| | | Pennsylvania | | West Virginia | | Kentucky | | Ohio | | Other (b) | | Total |
| Natural gas, oil and NGLs production (MMcfe) – 2017 (a) (c) | | 456,614 |
| | 352,481 |
| | 60,423 |
| | 24,426 |
| | 13,948 |
| | 907,892 |
|
| Natural gas, oil and NGLs production (MMcfe) – 2016 (a) | | 426,524 |
| | 272,529 |
| | 61,267 |
| | 541 |
| | 15,502 |
| | 776,363 |
|
| Natural gas, oil and NGLs production (MMcfe) – 2015 (a) | | 327,616 |
| | 208,376 |
| | 65,726 |
| | 859 |
| | 16,109 |
| | 618,686 |
|
| | | | | | | | | | | | | |
| Natural gas, oil and NGLs sales (MMcfe) – 2017 (c) | | 456,600 |
| | 343,199 |
| | 51,313 |
| | 24,113 |
| | 12,295 |
| | 887,520 |
|
| Natural gas, oil and NGLs sales (MMcfe) – 2016 | | 429,011 |
| | 264,452 |
| | 51,200 |
| | 536 |
| | 13,768 |
| | 758,967 |
|
| Natural gas, oil and NGLs sales (MMcfe) – 2015 | | 329,626 |
| | 200,121 |
| | 57,825 |
| | 758 |
| | 14,752 |
| | 603,082 |
|
| | | | | | | | | | | | | |
| Average net revenue interest of proved reserves (%) | | 79.7 | % | | 83.0 | % | | 92.7 | % | | 46.6 | % | | 79.8 | % | | 76.4 | % |
| | | | | | | | | | | | | |
| Total gross productive wells | | 1,654 |
| | 5,391 |
| | 5,723 |
| | 178 |
| | 1,660 |
| | 14,606 |
|
| Total net productive wells | | 1,595 |
| | 5,125 |
| | 5,412 |
| | 78 |
| | 1,490 |
| | 13,700 |
|
| | | | | | | | | | | | | |
| Total gross productive acreage | | 189,302 |
| | 329,357 |
| | 438,598 |
| | 40,878 |
| | 128,471 |
| | 1,126,606 |
|
| Total gross undeveloped acreage | | 502,534 |
| | 1,069,017 |
| | 1,057,288 |
| | 49,207 |
| | 194,422 |
| | 2,872,468 |
|
| Total gross acreage | | 691,836 |
| | 1,398,374 |
| | 1,495,886 |
| | 90,085 |
| | 322,893 |
| | 3,999,074 |
|
| | | | | | | | | | | | | |
| Total net productive acreage | | 180,714 |
| | 321,110 |
| | 432,007 |
| | 22,761 |
| | 102,241 |
| | 1,058,833 |
|
| Total net undeveloped acreage | | 486,232 |
| | 898,592 |
| | 985,424 |
| | 49,258 |
| | 167,080 |
| | 2,586,586 |
|
| Total net acreage | | 666,946 |
| | 1,219,702 |
| | 1,417,431 |
| | 72,019 |
| | 269,321 |
| | 3,645,419 |
|
| | | | | | | | | | | | | |
| (Amounts in Bcfe) | | |
| | |
| | |
| | | | |
| | |
|
| Proved developed producing reserves | | 5,569 |
| | 3,449 |
| | 1,226 |
| | 700 |
| | 162 |
| | 11,106 |
|
| Proved developed non-producing reserves | | 122 |
| | 13 |
| | — |
| | 58 |
| | — |
| | 193 |
|
| Proved undeveloped reserves | | 7,786 |
| | 1,313 |
| | — |
| | 1,048 |
| | — |
| | 10,147 |
|
| Proved developed and undeveloped reserves | | 13,477 |
| | 4,775 |
| | 1,226 |
| | 1,806 |
| | 162 |
| | 21,446 |
|
| | | | | | | | | | | | | |
| Gross proved undeveloped drilling locations | | 574 |
| | 126 |
| | — |
| | 107 |
| | — |
| | 807 |
|
| Net proved undeveloped drilling locations | | 539 |
| | 124 |
| | — |
| | 70 |
| | — |
| | 733 |
|
(a) All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.
(b) Other includes Virginia, Maryland and Texas.
| |
(c) | For the year ended December 31, 2017, the natural gas, oil and NGLs production volumes and sales volumes includes volumes from the production operations acquired in the Rice Merger for the period of November 13, 2017 through December 31, 2017. |
The Company sells natural gas within the Appalachian Basin and in markets accessible through its transportation portfolio under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves. As of December 31, 2017, the Company’s delivery commitments for the next five years were as follows:
|
| | |
| For the Year Ended December 31, | | Natural Gas (Bcf) |
| 2018 | | 1,173 |
| 2019 | | 671 |
| 2020 | | 459 |
| 2021 | | 335 |
| 2022 | | 259 |
Capital expenditures at EQT Production totaled $2.4 billion during 2017, including $1.0 billion for the acquisition of properties. The Company invested approximately $1,055.7 million during 2017 developing proved reserves and approximately $329.2 million on wells still in progress at year end. During the year ended December 31, 2017, the Company converted approximately 987 Bcfe of proved undeveloped reserves to proved developed reserves. The Company had additions to proved developed reserves of 4,455 Bcfe, including 3,330 Bcfe from acquired wells and 300 Bcfe from wells developed in 2017 that had not previously been classified as proved. The Company had negative revisions of 3,074 Bcfe of proved undeveloped reserves that are no longer anticipated to be drilled within 5 years of booking as a result of acquiring new acreage, which added 6,060 Bcfe of proved undeveloped reserves. The acquired acreage presents opportunities to drill considerably longer laterals, realize operational efficiencies and improve overall returns. As of December 31, 2017, the Company’s proved undeveloped reserves totaled 10.1 Tcfe, 90% of which is associated with the development of the Marcellus, including Upper Devonian, play. All proved undeveloped drilling locations are expected to be drilled within five years.
The Company’s 2017 extensions, discoveries and other additions totaled 2,225 Bcfe, which exceeded the 2017 production of 908 Bcfe. Of these reserves, 1,925 Bcfe are attributed to the addition of proved undeveloped locations in the Company’s Pennsylvania and West Virginia Marcellus fields and 300 Bcfe are from the development of locations not previously booked as proved.
Wells located in Pennsylvania are primarily in Marcellus formations with depths ranging from 5,000 feet to 8,000 feet. Wells located in West Virginia are primarily in Marcellus and Huron formations with depths ranging from 2,500 feet to 7,700 feet. Wells located in Kentucky are primarily in Huron formations with depths ranging from 2,500 feet to 6,500 feet. Wells located in Ohio are primarily in Utica formations with depths ranging from 8,500 feet to 10,500 feet. Other wells are in Coalbed Methane, deep Utica and Permian formations.
As a result of the changes to the Company's reporting segments effective for this Annual Report on Form 10-K, EQT Production operations include certain gathering assets, including the Rice retained gathering assets and certain non-core gathering operations primarily supporting the Company's production operations. See “EQT Production Business Segment” under Item 1, “Business”"Business" for a description of the midstream assets includedour properties. Our corporate headquarters is located in the EQT Production segment, which is incorporated herein by reference. Substantially all of the gathering operation’s transported volumes are delivered to interstate pipelines on which the Company and other customersleased office space in Pittsburgh, Pennsylvania. We also own or lease capacity. These pipelines are subject to periodic curtailments for maintenance and repairs.
EQT Production owns or leases office space in Pennsylvania, West Virginia, Ohio, Virginia Kentucky and Texas.
Headquarters: The Company’s corporate headquarters and other operations are located in leased office space in Pittsburgh, Pennsylvania.
For a description of material properties, see "EQM Gathering Business Segment," "EQM Transmission Business Segment," "RMP Gathering Business Segment" and "RMP Water Business Segment" under Item 1, "Business," which sections are incorporated herein by reference.
See “Capital Resources and Liquidity” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a discussion of capital expenditures.
Item 3. Legal Proceedings
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company.us. While the amounts claimed may be substantial, the Company iswe are unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accruesWe accrue legal and other direct costs related to loss contingencies when actually incurred. The Company hasWe have established reserves it believesin amounts that we believe to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believeswe believe that the ultimate outcome of any matter currently pending against the Companyus will not materially affect theimpact our financial condition,position, results of operations or liquidity of the Company.liquidity.
Environmental Proceedings
Phoenix S Impoundment, TiogaProduced Water Release, Marshall County, Pennsylvania
In June and August 2012, the CompanyWest Virginia. On November 12, 2019, we received three Noticesa Notice of Violation (NOVs) from the Pennsylvania Department of Environmental Protection (the PADEP). The NOVs alleged violations of the Pennsylvania Oil and Gas Act and Clean Streams Law in connection with the unintentional release in May 2012, by a Company vendor, of water from an impaired water pit at a Company well location in Tioga County, Pennsylvania. Since confirming a release, the Company has cooperated with the PADEP in remediating the affected areas.
During the second quarter of 2014, the Company received a proposed consent assessment of civil penalty from the PADEP that proposed a civil penalty related to the NOVs. On September 19, 2014, the Company filed a declaratory judgment action in the Commonwealth Court of Pennsylvania against the PADEP seeking a court ruling on the PADEP’s legal interpretation of the penalty provisions of the Clean Streams Law, which interpretation the Company believed was legally flawed and unsupportable. On October 7, 2014, based on its interpretation of the penalty provisions, the PADEP filed a complaint against the Company before the Pennsylvania Environmental Hearing Board (the EHB) seeking $4.53 million in civil penalties. In January 2017, the Commonwealth Court ruled in favor of the Company, finding the PADEP’s interpretation of the penalty provisions of the Clean Streams Law erroneous. The PADEP appealed that decision to the Pennsylvania Supreme Court, and the parties made oral arguments in front of the Pennsylvania Supreme Court on November 28, 2017. Following a July 2016 hearing before the EHB, in May 2017, the EHB ruled that the Company should pay $1.1 million in civil penalties. In June 2017, both the Company and the PADEP appealed the EHB’s decision to the Commonwealth Court. While the Company expects the PADEP’s claims to result in penalties that exceed $100,000, the Company expects the resolution of this matter will not have a material impact on the financial condition, results of operations or liquidity of the Company.
Allegheny Valley Connector, Cambria County, Pennsylvania
Between September 2015 and February 2016, EQM, as the operator of the Allegheny Valley Connector (AVC) facilities which at that time were owned by EQT, received eight NOVs from the PADEP. The NOVs alleged violations of the Pennsylvania Clean Streams Law in connection with inadvertent releases of sediment and bentonite to water that occurred while drilling for a pipeline replacement project in Cambria County, Pennsylvania. EQT and EQM immediately addressed the releases and fully cooperated with the PADEP. In October 2016, EQM acquired the AVC facilities from EQT, including any future obligations related to these releases. In February 2017, EQM received a proposed consent assessment of civil penalty from the PADEP that proposed a civil penalty related to the NOVs. While the PADEP’s claims may result in penalties that exceed $100,000, the Company expects that the resolution of this matter will not have a material impact on the financial condition, results of operations or liquidity of the Company or EQM.
Trans Energy, Inc. Matter, West Virginia
As described in Note 10 to the Consolidated Financial Statements, the Company completed the acquisition of Trans Energy, Inc. (Trans Energy) on December 5, 2016. Between 2009 and 2011, Trans Energy received several NOVs(NOV) from the West Virginia Department of Environmental Protection (the WVDEP) as well as seven Compliance Orders from the U.S. Environmental Protection Agency (the EPA). The NOVs and Compliance Orders alleged various violations of the federal Clean Water Act related(WVDEP) relating to the filling of streams and wetlands to create impoundments at several well padsGoshorn Pad in Marshall Wetzel and Marion Counties,County, West Virginia.
On August 25, 2014, Trans Energy entered into a civil consent decree with the EPA (the Consent Decree) to settle the various violations of the Clean Water Act. The Consent Decree requires, among other things, numerous restoration activities associated with impoundments, well pads and access roads in West Virginia at an estimated cost of $10 - $15 million.
On October 1, 2014, pursuant to a plea agreement, Trans Energy pleaded guilty to three misdemeanor charges filed by the U.S. Attorney for the Northern District of West Virginia related to the same violations of the Clean Water Act that were the subject of the Consent Decree.
On December 21, 2015, Trans Energy entered into an Administrative Agreement with the EPA’s Office of Suspension and Debarment to resolve all matters relating to suspension, debarment and statutory disqualification arising from the plea agreement. The EPA terminated the Administrative Agreement effective as of October 25, 2017. The Administrative Agreement required, among other things, Trans Energy to comply with the plea agreement and Consent Decree, prepare semiannual compliance reports, and retain an independent monitor to certify Trans Energy’s compliance.
Fresh Water Pipeline Bore Release, Allegheny County, Pennsylvania
On February 24, 2017, the Company received an NOV from the PADEP. The NOV alleged violations of the Pennsylvania Oil and Gas Act and Clean Streams Law related to an unintentionalWater Pollution Control Rules in connection with a release byof produced water from secondary containment at a Company vendor, of mine water into the Monongahela River in January 2017 from a mine void that was pierced while boring under a road for the installation of a fresh water pipeline in Allegheny County, Pennsylvania. The CompanyGoshorn Pad tank battery. We cooperated fully with the PADEPWVDEP to take appropriate actions to stopaddress the release. On February 15, 2017, the Company entered into a civil penalty settlement related tosecondary containment issues and remediation of the release, with the Pennsylvania Fish and Boat Commissionthis matter was substantially resolved in March 2020. We were not assessed any monetary penalty for $4,555 for alleged violations of the Pennsylvania Fishthis matter, and Boat Code. Settlement discussions between the Company and the PADEP are ongoing. While the Company expects the PADEP’s claims to result in penalties that exceed $100,000, the Company expects that the resolution of this matter willdid not have a material impact on theour financial condition,position, results of operations or liquidityliquidity.
Secondary Containment underneath Gas Processing Units (GPUs), Allegheny, Greene and Washington Counties, Pennsylvania. On April 1, 2020, we received a draft Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (PADEP) claiming that we failed to install secondary containment systems in accordance with 25 Pa. Code § 78a.64a(b) underneath 228 GPUs located in southwest Pennsylvania between October 8, 2016 and February 4, 2019. On February 4, 2019, we voluntarily disclosed a list of GPUs that did not meet the Company.requirements of 25 Pa. Code § 78a.64a(b). On December 17, 2020, we entered into the Consent Order and Agreement with PADEP, pursuant to which we agreed to install
secondary containment systems in compliance with 25 Pa. Code § 78a.64a(b) on all new GPU installations going forward, among other things, and this matter was resolved. We were not assessed any monetary penalty for this matter, and the resolution of this matter did not have a material impact on our financial position, results of operations or liquidity.
Other Legal Proceedings
Mary Farr Secrist, et al. v. EQT Production Company, et al., Circuit Court of Doddridge County, West Virginia. On May 2, 2014, royalty owners whose predecessors had entered into a 960-acre lease (the Stout Lease) and several additional leases comprising 6,356-acres (the Cities Services Lease) with EQT Production Company's predecessor, each covering acreage in Doddridge County, West Virginia, filed a complaint in the Circuit Court of Doddridge County, West Virginia. The complaint alleged that EQT Production Company has receivedand a number of related companies, including EQT Corporation, EQT Gathering, LLC, EQT Energy, LLC, and EQM Midstream Services, LLC (formerly known as EQT Midstream Services, LLC, the general partner of our former midstream affiliate), underpaid on royalties for gas produced under the leases and took improper post-production deductions from the royalties paid. With respect to the Stout Lease, the plaintiffs also asserted that we committed a trespass by drilling on the leased property, claiming that we had no right under the lease to drill in the Marcellus Shale formation. The plaintiffs also asserted claims for fraud, slander of title, punitive damages, pre-judgment interest and attorneys' fees. The plaintiffs sought more than $100 million in compensatory damages for the trespass claim under the Stout Lease, and approximately $20 million for insufficient royalties under both the Stout Lease and the Cities Services Lease, in addition to punitive damages and other NOVsrelief. On June 27, 2018, the Court held that EQT Production Company and its marketing affiliate EQT Energy, LLC are alter egos of one another and that royalties paid under the leases should have been based on the price of gas produced under the leases when sold to unaffiliated third parties, and not on the price when the gas was sold from environmental agenciesEQT Production Company to EQT Energy, LLC. Further, on January 14, 2019, the Court entered an Order granting the plaintiffs' motion for summary judgment and declaring that we did not have the right to drill in somethe Marcellus Shale formation under the Stout Lease. The Court also ruled that seven of our wells that have been producing gas under the Stout Lease are trespassing, and that a jury will determine whether the trespass was willful or innocent. On February 27, 2019, we filed a motion seeking permission to immediately appeal the trespass Order to the West Virginia Supreme Court; however, the motion was denied on March 25, 2019, and the Court continued the trial to September 2019. On May 28, 2019, the Court entered an Order excluding certain of our costs that could have otherwise offset any damages for innocent trespass under the Stout Lease. On August 8, 2019, we reached a settlement with the plaintiffs to resolve all claims under the Stout Lease and the Cities Services Lease for $54 million plus lease modifications to address the trespass issue and the calculation of future royalty payments under the leases. We paid $51 million of the statessettlement in October 2019 and the remaining $3 million of the settlement in January 2020, and the Stout Lease was subsequently amended to address the terms agreed to with the plaintiffs under the settlement. On October 7, 2020, the plaintiffs filed a motion to amend their complaint and to stay entry of an Order of Dismissal. On January 14, 2021, we filed a motion to enforce the settlement agreed to with the plaintiffs and to seek sanctions. All recent motions are pending.
Hammerhead Gathering Agreement Dispute. EQT Corporation and Equitrans Midstream, through certain of our and their subsidiaries, are parties to a gas gathering agreement (the Hammerhead Gathering Agreement) related to Equitrans Midstream's Hammerhead Gas Gathering System. Pursuant to the terms of the Hammerhead Gathering Agreement, if the "In-Service Date" did not occur on or before October 1, 2020, we may terminate the Hammerhead Gathering Agreement and purchase the Hammerhead Gas Gathering System from Equitrans Midstream for an amount equal to 88% of expenses actually incurred and other obligations made or to be incurred by Equitrans Midstream. The "In-Service Date" is defined in the Hammerhead Gathering Agreement as "the later of (i) the first Day of the Month immediately following the date on which Gatherer is first able to provide the Gathering Services to Shipper in accordance with the Hammerhead Gathering Agreement and (ii) the first Day of the Month immediately following the date on which the Company operates alleging various violations of oil and gas, air, water and waste regulations. The Company has respondedInterconnect Facilities connecting the Gathering System to these NOVs and has, where applicable, substantially corrected or remediated the activities in question. The Company disputes the facts alleged in a numberMountain Valley Pipeline are first able to receive deliveries of the NOVsContract MDQ." On September 24, 2020, we initiated arbitration proceedings against Equitrans Midstream, seeking a declaration that we are entitled to terminate the Hammerhead Gathering Agreement and cannot predict with certainty whether any or allpurchase the Hammerhead Gas Gathering System. The deadline for us to provide notice of these NOVs will resultour election to terminate the Hammerhead Gathering Agreement and purchase the Hammerhead Gas Gathering System has been tolled while the contract claim is pending in penalties. If penalties are imposed, an individual penalty or the aggregate of these penalties could result in monetary sanctions in excess of $100,000.arbitration.
Item 4.Mine Safety Disclosures
Not Applicable.
Information about our Executive Officers of the Registrant (as of February 15, 2018)
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| | | | | | | | | | | | | |
| Name and Age | | Current Title (Year Initially Elected an Executive Officer) | | Business Experience |
| Tony Duran (42) | | Chief Information Officer (2019) | | |
Jeremiah J. Ashcroft III (45) | | Senior Vice President,Mr. Duran was appointed as the Chief Information Officer of EQT Corporation and President, Midstream (2017) | | Elected to present position August 2017. Mr. Ashcroft is also a Director and Senior Vice President and Chief Operating Officer of each of EQT Midstream Services, LLC, the general partner of EQM, since August 2017, and Rice Midstream Management LLC, the general partner of RMP, since November 2017.in July 2019. Prior to joining EQT Corporation, Mr. AshcroftDuran ran PH6 Labs, a technology incubator he founded, from December 2017 to July 2019. Prior to that, he served as President andthe Chief ExecutiveInformation Officer of Gulf Oil L.P.,Rice Energy Inc. (independent natural gas and oil company acquired by EQT Corporation in November 2017) from January 2016 to November 2017; and as the Interim Chief Information Officer of Express Energy Services (oilfield services company for well construction and well testing services) from September 2015 to June 2017; ExecutiveDecember 2015. Additionally, Mr. Duran held various positions at National Oilwell Varco (multinational corporation that provides equipment and components used in oil and gas drilling and production operations, oilfield services, and supply chain integration services to the upstream oil and gas industry) from May 2002 to August 2015, where he last held the role of Assistant Chief Information Officer. |
| Lesley Evancho (43) | | Chief Human Resources Officer (2019) | | Ms. Evancho was appointed as the Chief Human Resources Officer of EQT Corporation in July 2019. Prior to joining EQT Corporation, Ms. Evancho served as Vice President, Global Talent Management at Westinghouse Electric Company, LLC (nuclear power, fuel and Chief Operating Officer of JP Energy Partners, LP,services company) from May 2014April 2019 to September 2015; andJuly 2019; Senior Director, Human Resources at Thermo Fisher Scientific, Inc. (biotechnology product development company) from August 2018 to March 2019; Vice President, of Buckeye Partners, L.P.’s Natural Gas Storage, Development & Logistics and Energy Services business units,Human Resources at Edward Marc Brands (food services company) from January 2012March 2018 to May 2014. |
| | | | |
Lewis B. Gardner (60) | | General CounselAugust 2018; and Vice President, External Affairs (2008)Human Resources at Rice Energy Inc. from April 2017 to November 2017. Additionally, Ms. Evancho served as Global Director, Talent Management at MSA Safety, Inc. (manufacturer of industrial safety equipment) from November 2011 to April 2017. |
| Todd M. James (38) | | Elected to present position March 2008. Chief Accounting Officer (2019) | | Mr. Gardner is also a Director of eachJames was appointed as the Chief Accounting Officer of EQT Midstream Services, LLC, the general partner of EQM, since January 2012, EQT GP Services, LLC, the general partner of EQGP, since January 2015, and Rice Midstream Management LLC, the general partner of RMP, sinceCorporation in November 2017. |
| | | | |
Donald M. Jenkins (45) | | Chief Commercial Officer (2017) | | Elected to present position March 2017. Mr. Jenkins served as Executive Vice President, Commercial, EQT Energy, LLC, from May 2014 to February 2017; and Senior Vice President, Trading and Origination, EQT Energy, LLC, from December 2012 to May 2014. |
| | | | |
Robert J. McNally (47) | | Senior Vice President and Chief Financial Officer (2016) | | Elected to present position March 2016. Mr. McNally is also a Director and Senior Vice President and Chief Financial Officer of each of EQT Midstream Services, LLC, the general partner of EQM, since March 2016, EQT GP Services, LLC, the general partner of EQGP, since March 2016, and Rice Midstream Management LLC, the general partner of RMP, since November 2017.2019. Prior to joining EQT Corporation, Mr. McNallyJames served as the Corporate Controller and Chief Accounting Officer of L.B. Foster Company (manufacturer and distributor of products and services for transportation and energy infrastructure) from April 2018 to October 2019. Prior to that he served as the Senior Director, Technical Accounting and Financial Reporting at Rice Energy Inc. from December 2014 through its acquisition by EQT Corporation in November 2017 and until February 2018. Prior to joining Rice Energy, Mr. James was a Senior Manager, Assurance at PricewaterhouseCoopers LLP (public accounting firm), where he worked from August 2005 to November 2014. |
| William E. Jordan (40) | | Executive Vice President, General Counsel and Corporate Secretary (2019) | | Mr. Jordan was appointed as the Executive Vice President and General Counsel of EQT Corporation in July 2019 and assumed the role of Corporate Secretary in November 2020. Mr. Jordan served as an advisor to the Rice Investment Group (multi-strategy investment fund investing in all verticals of the oil and gas sectors) from May 2018 until July 2019. Prior to that, he served as the Senior Vice President, General Counsel and Corporate Secretary of Rice Energy Inc. and Senior Vice President, General Counsel and Corporate Secretary of Rice Midstream Partners LP (former midstream services affiliate of Rice Energy Inc.), in each case from January 2014 until their acquisition by EQT Corporation in November 2017. From September 2005 to December 2013, Mr. Jordan was an associate at Vinson & Elkins LLP (an international law firm) representing public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry. |
| David M. Khani (57) | | Chief Financial Officer (2020) | | Mr. Khani was appointed as the Chief Financial Officer of EQT Corporation in January 2020. Prior to joining EQT Corporation, Mr. Khani served as the Executive Vice President and Chief Financial Officer of Precision Drilling Corporation,CONSOL Energy (energy company primarily focused on developing coal interests), from March 2013 to December 2019; and as Vice President, Finance at CONSOL Energy from September 2011 to March 2013. In addition, Mr. Khani served as Chief Financial Officer and as a publicly traded drillingmember of the Board of Directors of CONE Midstream LLC (midstream services company,affiliate of CONSOL Energy) from September 2014 to January 2018; as a member of the Board of Directors of CNX Coal Resources (coal mining affiliate of CONSOL Energy) from July 20102015 to March 2016.August 2017; and as Chief Financial Officer and as a member of the Board of Directors of CONSOL Coal Resources (coal mining affiliate of CONSOL Energy) from August 2017 to December 2019. |
| Toby Z. Rice (39) | | | | |
Charlene Petrelli (57) | | Vice President and Chief Human Resources Officer (2003) | | Elected to present position February 2007. |
| | | | |
David L. Porges (60) | | Executive Chairman (1998) | | Elected to present position March 2017. Mr. Porges served as Chairman and Chief Executive Officer, EQT Corporation, from December 2015 to February 2017; Chairman, President and Chief Executive Officer EQT Corporation, from May 2011 to December 2015; and President and Chief Executive Officer of each of EQT Midstream Services, LLC, the general partner of EQM, from January 2012 to February 2017, and EQT GP Services, LLC, the general partner of EQGP, from January 2015 to February 2017. (2019)
| | Mr. Porges has served as a Director of the Company since May 2002 and also Chairman of the Boards of Directors of the general partners of EQGP, EQM and RMP, since January 2015, January 2012 and November 2017, respectively. As previously disclosed in the Company’s Form 8-K filed with the SEC on January 18, 2018, Mr. Porges intends to retire from his position as Executive Chairman of the Company on February 28, 2018. Following that time, he will continue to serve as a non-executive Chairman of the Company’s Board of Directors.
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| | | | |
David E. Schlosser, Jr. (52) | | Senior Vice President, EQT Corporation and President, Exploration and Production (2017) | | Elected to present position March 2017. Mr. Schlosser served as Executive Vice President, Engineering, Geology and Planning, EQT Production Company, from October 2014 to February 2017; and Senior Vice President, Engineering and Strategic Planning, EQT Production Company, from March 2012 to September 2014. |
| | | | |
Steven T. Schlotterbeck (52) | | President and Chief Executive Officer (2008) | | Elected to present position March 2017. Mr. Schlotterbeck served as President, EQT Corporation and President, Exploration and Production from December 2015 to February 2017; Executive Vice President, EQT Corporation and President, Exploration and Production from December 2013 to December 2015; and Senior Vice President, EQT Corporation and President, Exploration and Production from April 2010 to December 2013. Mr. Schlotterbeck has also servedRice was appointed as President and Chief Executive Officer of eachEQT Corporation in July 2019, when he also was elected to EQT Corporation's Board of Directors. Mr. Rice has served as a Partner at the Rice Investment Group, a multi-strategy fund investing in all verticals of the oil and gas sector, since May 2018. From October 2014 until its acquisition by EQT Corporation in November 2017, Mr. Rice was President and Chief Operating Officer of Rice Energy Inc. and served on the Board of Directors of Rice Energy Inc. from October 2013 to November 2017. Prior to that, he served in a number of positions with Rice Energy, its affiliates and predecessor entities beginning in February 2007, including as President and Chief Executive Officer of a predecessor entity from February 2008 through September 2013. Mr. Rice is the brother of Daniel J. Rice IV, a member of EQT GP Services, LLC, the general partnerCorporation's Board of EQGP, since March 2017, EQT Midstream Services, LLC, the general partner of EQM, since March 2017, and Rice Midstream Management LLC, the general partner of RMP,Directors since November 2017. Mr. Schlotterbeck is also a Director of each of EQT Corporation, since January 2017, EQT GP Services, LLC, since January 2015, EQT Midstream Services, LLC, since January 2017, and Rice Midstream Management LLC, since November 2017. |
| | | | |
Jimmi Sue Smith (45) | | Chief Accounting Officer (2016) | | Elected to present position September 2016. Ms. Smith served as Vice President and Controller of the Company's midstream and commercial businesses from March 2013 to September 2016; and Vice President and Controller of the Company's midstream business from January 2013 through March 2013. Ms. Smith is also Chief Accounting Officer of each of EQT Midstream Services, LLC, the general partner of EQM, since September 2016, EQT GP Services, LLC, the general partner of EQGP, since September 2016, and Rice Midstream Management LLC, the general partner of RMP, since November 2017. |
All executive officers have either elected to participate in the EQT Corporation Executive Severance Plan (which includes confidentiality and non-compete provisions) or executed non-compete agreements with EQT Corporation, and each of the Company andexecutive officers serve at the pleasure of the Company’sour Board of Directors. Officers are elected annually to serve during the ensuing year or until their successors are elected and qualified, or until death, resignation or removal.
PART II
Item 5.Market for Registrant’sRegistrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Company’sOur common stock is listedtraded on the New York Stock Exchange. The high and low sales prices reflected inExchange under the New York Stock Exchange Composite Transactions and the dividends declared and paid per share for 2017 and 2016 are summarized as follows (in U.S. dollars per share):
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2017 | | 2016 |
| | | High | | Low | | Dividend | | High | | Low | | Dividend |
| 1st Quarter | | $ | 66.41 |
| | $ | 56.33 |
| | $ | 0.03 |
| | $ | 68.26 |
| | $ | 48.30 |
| | $ | 0.03 |
|
| 2nd Quarter | | 64.45 |
| | 49.63 |
| | 0.03 |
| | 80.61 |
| | 63.48 |
| | 0.03 |
|
| 3rd Quarter | | 67.84 |
| | 57.49 |
| | 0.03 |
| | 79.64 |
| | 67.69 |
| | 0.03 |
|
| 4th Quarter | | 66.03 |
| | 53.43 |
| | 0.03 |
| | 75.74 |
| | 63.11 |
| | 0.03 |
|
As of January 31, 2018,February 12, 2021, there were 2,3581,985 shareholders of record of the Company’sour common stock.
On March 26, 2020, we announced the suspension of our quarterly cash dividend on our common stock for purposes of accelerating cash flow to be used for our Deleveraging Plan. The amount and timing of dividends isdeclared and paid by us, if any, are subject to the discretion of theour Board of Directors and depends uponon business conditions, such as the Company’s lines of business,our results of operations and financial condition, strategic direction and other factors. TheOur Board of Directors hashave the discretion to change the annual dividend rate at any time for any reason.
Recent Sales of Unregistered Securities
None.
Market Repurchases
The following table sets forth the Company’s repurchases ofWe did not repurchase any equity securities registered under Section 12 of the Securities Exchange Act of 1934, as amended, that occurred during the three months ended December 31, 2017:2020.
|
| | | | | | | | | | | | | |
| Period | | Total number of shares purchased (a) | | Average price paid per share | | Total number of shares purchased as part of publicly announced plans or programs | | Maximum number of shares that may yet be purchased under the plans or programs (b) |
| October 2017 (October 1 – October 31) | | — |
| | $ | — |
| | — |
| | 700,000 |
|
| November 2017 (November 1 – November 30) | | 788,066 |
| | 65.15 |
| | — |
| | 700,000 |
|
| December 2017 (December 1 – December 31) | | 53,443 |
| | 64.62 |
| | — |
| | 700,000 |
|
| Total | | 841,509 |
| | $ | 65.11 |
| | — |
| |
|
|
(a)Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock.
(b) On April 30, 2014, the Company’s Board of Directors announced a share repurchase authorization of up to 1,000,000 shares of the Company’s outstanding common stock. The Company may repurchase shares from time to time in open market or in privately negotiated transactions. The share repurchase authorization does not obligate the Company to acquire any specific number of shares, has no pre-established end date and may be discontinued by the Company at any time. As of December 31, 2017, the Company had repurchased 300,000 shares under this authorization since its inception.
Stock Performance Graph
The following graph compares the most recent cumulative five-year cumulative total return attained by holdersprovided to shareholders of our common stock relative to the cumulative five-year total returns of the Company’sStandard & Poor’s (S&P) 500 Index, the S&P MidCap 400 Index and two customized peer groups, the 2019 Self-Constructed Peer Group and 2020 Self-Constructed Peer Group, whose company composition is discussed in footnotes (a) and (b), respectively, below. Our common stock with cumulative returns ofwas included in the S&P 500 Index until the Separation and a customized peer group. The individual companies ofDistribution in 2018, following which our common stock was added to the prior customized peer group (the 2016 Self-Constructed Peer Group) andS&P MidCap 400 Index. We have presented both indices for comparison in the new customized peer group (the 2017 Self-Constructed Peer Group) are listed below.following graph. An investment of $100, (withwith reinvestment of all dividends)dividends, is assumed to have been made at the close of business on December 31, 2012 in the Company’sour common stock, in the S&P 500 Index, the S&P MidCap 400 Index and in each customizedof the peer group. Relativegroups on December 31, 2015 and its relative performance is tracked through December 31, 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 12/12 | | 12/13 | | 12/14 | | 12/15 | | 12/16 | | 12/17 |
| EQT Corporation | | $ | 100.00 |
| | $ | 152.46 |
| | $ | 128.71 |
| | $ | 88.77 |
| | $ | 111.58 |
| | $ | 97.30 |
|
| S&P 500 | | 100.00 |
| | 132.39 |
| | 150.51 |
| | 152.59 |
| | 170.84 |
| | 208.14 |
|
| 2016 Self-Constructed Peer Group (a) | | 100.00 |
| | 139.77 |
| | 116.14 |
| | 73.35 |
| | 109.56 |
| | 103.76 |
|
| 2017 Self-Constructed Peer Group (b) | | 100.00 |
| | 137.94 |
| | 115.12 |
| | 71.23 |
| | 105.10 |
| | 98.82 |
|
| |
(a) | The 2016 Self-Constructed Peer Group includes the following 21 companies: Cabot Oil & Gas Corp, Chesapeake Energy Corp, Cimarex Energy Co, Concho Resources Inc., CONSOL Energy Inc. (now known as CNX Resources Corp), Continental Resources Inc., Energen Corp, EOG Resources Inc., EXCO Resources Inc., Marathon Oil Corp, National Fuel Gas Co, Newfield Exploration Co, Noble Energy Inc., ONEOK Inc., Pioneer Natural Resources Co, QEP Resources Inc., Range Resources Corp, SM Energy Co, Southwestern Energy Co, Ultra Petroleum Corp and Whiting Petroleum Corp. Spectra Energy Corp was included in the self-constructed peer group that served as the basis for the stock performance chart in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 but has been excluded from the 2016 Self-Constructed Peer Group above as it was acquired. |
| |
(b) | The 2017 Self-Constructed Peer Group includes the following 22 companies: Antero Resources Corp, Cabot Oil & Gas Corp, Chesapeake Energy Corp, Cimarex Energy Co, Concho Resources Inc., CONSOL Energy Inc. (now known as CNX Resources Corp), Continental Resources Inc., Devon Energy Corp, Energen Corp, EOG Resources Inc., EXCO Resources Inc., Marathon Oil Corp, National Fuel Gas Co, Newfield Exploration Co, Noble Energy Inc., ONEOK Inc., Pioneer Natural Resources Co, QEP Resources Inc., Range Resources Corp, SM Energy Co, Southwestern Energy Co, and Whiting Petroleum Corp. The 2017 Self-Constructed Peer Group is the peer group that is used for the Company’s 2017 Incentive Performance Share Unit Program, which utilizes three-year total shareholder return against the peer group as one performance metric. It is also identical to the 2016 Self-Constructed Peer Group after adjusting for the removal of Spectra Energy Corp (acquired) and Ultra Petroleum Corp (filed for bankruptcy) and the addition of Antero Resources Corp and Devon Energy Corp (determined by the Company’s Management Development and Compensation Committee (the Compensation Committee) to be appropriate peers). |
Equity Compensation Plans*$100 invested on 12/31/15 in stock, index, or peer group, including reinvestment of dividends.
See Item 12, “Security OwnershipCopyright© 2021 Standard & Poor’s, a division of Certain Beneficial OwnersS&P Global. All right reserved.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 12/15 | | 12/16 | | 12/17 | | 12/18 | | 12/19 | | 12/20 |
| EQT Corporation | $ | 100.00 | | | $ | 125.69 | | | $ | 109.60 | | | $ | 67.06 | | | $ | 39.01 | | | $ | 45.74 | |
| S&P 500 | 100.00 | | | 111.96 | | | 136.40 | | | 130.42 | | | 171.49 | | | 203.04 | |
| S&P MidCap 400 Index | 100.00 | | | 120.74 | | | 140.35 | | | 124.80 | | | 157.49 | | | 179.00 | |
| 2019 Self-Constructed Peer Group (a) | 100.00 | | | 148.63 | | | 129.24 | | | 77.93 | | | 60.57 | | | 49.24 | |
| 2020 Self-Constructed Peer Group (b) | 100.00 | | | 132.65 | | | 108.37 | | | 72.36 | | | 49.65 | | | 50.87 | |
(a)The 2019 Self-Constructed Peer Group includes the following twelve companies: Antero Resources Corp., Cabot Oil & Gas Corp., Chesapeake Energy Corp., Cimarex Energy Co., CNX Resources Corp., Gulfport Energy Corp., Murphy Oil Corp., Ovintiv Inc. (formerly Encana Corp.), QEP Resources, Inc., Range Resources Corp., SM Energy Co. and ManagementSouthwestern Energy Co. WPX Energy Inc. was included in the self-constructed peer group that served as the basis for the stock performance graph in our Annual Report on Form 10-K for the year ended December 31, 2019, but it has been excluded from the 2019 Self-Constructed Peer Group because it was acquired during 2020.
(b)The 2020 Self-Constructed Peer Group includes the following eight companies: Antero Resources Corp., Cabot Oil & Gas Corp., Chesapeake Energy Corp., CNX Resources Corp., Comstock Resources, Inc., Gulfport Energy Corp., Range Resources Corp. and Related Stockholder Matters,” for informationSouthwestern Energy Co. The 2020 Self-Constructed Peer Group is comprised of the companies included in our 2020 performance peer group, as set forth in our definitive proxy statement relating to compensation plansour 2020 annual meeting of shareholders, and were selected by the Management Development and Compensation Committee of the Board of Directors for purposes of evaluating our relative total shareholder return under which the Company’s securities are authorized for issuance.2020 Incentive Performance Share Unit Program.
Item 6.Selected Financial Data
Not Applicable.
|
| | | | | | | | | | | | | | | | | | | | |
| | | As of and for the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | (Thousands, except per share amounts) |
| Total operating revenues | | $ | 3,378,015 |
| | $ | 1,608,348 |
| | $ | 2,339,762 |
| | $ | 2,469,710 |
| | $ | 1,862,011 |
|
| | | | | | | | | | | |
| Amounts attributable to EQT Corporation: | | | | | | | | | | |
| Income (loss) from continuing operations | | $ | 1,508,529 |
| | $ | (452,983 | ) | | $ | 85,171 |
| | $ | 385,594 |
| | $ | 298,729 |
|
| Net income (loss) | | $ | 1,508,529 |
| | $ | (452,983 | ) | | $ | 85,171 |
| | $ | 386,965 |
| | $ | 390,572 |
|
| | | | | | | | | | | |
| Earnings per share of common stock attributable to EQT Corporation: | | | | |
| | |
|
| Basic: | | | | |
| | |
| | |
| | |
|
| Income (loss) from continuing operations | | $ | 8.05 |
| | $ | (2.71 | ) | | $ | 0.56 |
| | $ | 2.54 |
| | $ | 1.98 |
|
| Net income (loss) | | $ | 8.05 |
| | $ | (2.71 | ) | | $ | 0.56 |
| | $ | 2.55 |
| | $ | 2.59 |
|
| | | | | | | | | | | |
| Diluted: | | | | | | | | | | |
| Income (loss) from continuing operations | | $ | 8.04 |
| | $ | (2.71 | ) | | $ | 0.56 |
| | $ | 2.53 |
| | $ | 1.97 |
|
| Net income (loss) | | $ | 8.04 |
| | $ | (2.71 | ) | | $ | 0.56 |
| | $ | 2.54 |
| | $ | 2.57 |
|
| Total assets | | $ | 29,522,604 |
| | $ | 15,472,922 |
| | $ | 13,976,172 |
| | $ | 12,035,353 |
| | $ | 9,765,907 |
|
| Long-term debt | | $ | 7,331,554 |
| | $ | 3,289,459 |
| | $ | 2,793,343 |
| | $ | 2,959,353 |
| | $ | 2,475,370 |
|
| Cash dividends declared per share of common stock | | $ | 0.12 |
| | $ | 0.12 |
| | $ | 0.12 |
| | $ | 0.12 |
| | $ | 0.12 |
|
See Item 1A, “Risk Factors”, Item 7, “Management’s7.Management's Discussion and Analysis of Financial Condition and Results of Operations” and Notes 1, 2, 9 and 10 to the Consolidated Financial Statements for a discussion of matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.Operations
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read theThe following discussion and analysis of financial condition and results of operations should be read in conjunction with the consolidated financial statements,Consolidated Financial Statements and the notes thereto included in Item 8 of this Annual Report on Form 10-K.8., "Financial Statements and Supplementary Data."
Consolidated Results of Operations
2017 EQT Highlights:
ClosedNet loss for 2020 was $967 million, $3.71 per diluted share, an improvement of $255 million compared to net loss for 2019 of $1,222 million, $4.79 per diluted share. The variance was attributable primarily to decreased impairments, the Rice Mergergain on November 13, 2017
Achieved annual production sales volumes of 887.5 Bcfe, 17% higher than 2016
Completed the 2017 Notes OfferingEquitrans Share Exchange (defined and discussed in Note 155 to the Consolidated Financial Statements) totaling $3.0 billion
Received FERC Certificate for Mountain Valley Pipeline
Net income attributable to EQT Corporation for 2017 was $1,508.5 million, $8.04 per diluted share, compared with a loss attributable to EQT Corporation of $453.0 million, a loss of $2.71 per diluted share, in 2016. The $1,961.5 million increase in net income attributable to EQT Corporation was primarily attributable to an income tax benefit recorded as a result of the lower federal corporate tax rate beginning in 2018, the result of a gain on derivatives not designated as hedges in 2017 compared to a loss in 2016, a 23% increase in the average realized price, a 17% increase in production sales volumes,, decreased other operating expenses, decreased depreciation and higher pipeline, waterdepletion expense and net marketing services, partiallydecreased transportation and processing expense, partly offset by higherdecreased operating expenses, higherrevenues, increased interest expense higher net income attributable to noncontrolling interests and a lossdecreased dividend and other income.
See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on debt extinguishment in 2017.
DuringForm 10-K for the year ended December 31, 2017, the Company recorded acquisition expenses2019, which is incorporated herein by reference, for discussion and analysis of approximately $237.3 million related to the Rice Merger, including $141.3 millionconsolidated results of employee related expensesoperations for payments to former Rice employees under the Merger Agreement. Additional expenses were for investment banking, legal and other professional fees. Acquisition costs are reflected in unallocated expenses and not recorded on any operating segment.
EQT Production received $40.7 million and $279.4 million of net cash settlements for derivatives not designated as hedges for the years ended December 31, 2017 and 2016, respectively, that are included in the average realized price but are not in GAAP operating revenues.
Net loss attributable to EQT Corporation for 2016 was $453.0 million, a loss of $2.71 per diluted share, compared with net income attributable to EQT Corporation of $85.2 million, $0.56 per diluted share, in 2015. The $538.2 million decrease in income attributable to EQT Corporation was primarily attributable to a loss on derivatives not designated as hedges, a 20% decrease in the average realized price, higher operating expenses and higher net income attributable to noncontrolling interests, partially offset by a 26% increase in production sales volumes and lower income tax expense.
EQT Production received $279.4 million and $172.1 million of net cash settlements for derivatives not designated as hedges for the years ended December 31, 2016 and 2015, respectively, that are included in the average realized price but are not in GAAP
operating revenues.
During the year ended December 31, 2016, the Company recorded an impairment of long-lived assets of approximately $59.7 million related to certain gathering assets sold to EQM in October 2016. The impairment was a result of a reduction in estimated future cash flows caused by the low commodity price environment and the related reduced producer drilling activity and throughput. This impairment is reflected in unallocated expenses and not recorded on any operating segment.2018.
See “Business Segment Results of Operations”"Sales Volumes and Revenues" and "Operating Expenses" for a discussiondiscussions of items impactingaffecting operating income “Otherand "Other Income Statement Items”Items" for a discussion of other income interest expense, income taxes and net income attributable to noncontrolling interests, and “Investing Activities”statement items. See "Investing Activities" under the caption “Capital"Capital Resources and Liquidity”Liquidity" for a discussion of capital expenditures.
Consolidated Operational DataAverage Realized Price Reconciliation
The following table presents detailed natural gas and liquids operational information to assist in the understanding of the Company’sour consolidated operations, including the calculation of the Company'sour average realized price ($/Mcfe), which is based on EQT Production adjusted operating revenues, a non-GAAP supplemental financial measure. EQT Production adjustedAdjusted operating revenues is presented because it is an important measure used by the Company’s managementwe use to evaluate period-to-period comparisons of earnings trends. EQT Production adjustedAdjusted operating revenues should not be considered as an alternative to EQT Production total operating revenues. See “Reconciliation of Non-GAAP"Non-GAAP Financial Measures”Measures Reconciliation" for a reconciliation of EQT Production
adjusted operating revenues to EQT Productionwith total operating revenues, and Note 6 to the Consolidated Financial Statements for a reconciliation of EQT Production total operating revenues to EQT Corporation total operating revenues.most directly comparable financial measure calculated in accordance with GAAP.
| | | | | | | | | | Years Ended December 31, |
| | Years Ended December 31, | | 2020 | | 2019 |
| in thousands (unless noted) | 2017 (e) | | 2016 | | 2015 | |
| | | (Thousands, unless otherwise noted) |
| NATURAL GAS | | | | | | NATURAL GAS | | |
| Sales volume (MMcf) | 774,076 |
| | 683,495 |
| | 547,094 |
| Sales volume (MMcf) | 1,418,774 | | | 1,435,134 | |
| NYMEX price ($/MMBtu) (a) | $ | 3.09 |
| | $ | 2.47 |
| | $ | 2.66 |
| NYMEX price ($/MMBtu) (a) | $ | 2.09 | | | $ | 2.63 | |
| Btu uplift | $ | 0.27 |
| | $ | 0.22 |
| | $ | 0.25 |
| Btu uplift | 0.11 | | | 0.13 | |
| Natural gas price ($/Mcf) | $ | 3.36 |
| | $ | 2.69 |
| | $ | 2.91 |
| Natural gas price ($/Mcf) | $ | 2.20 | | | $ | 2.76 | |
| | | | | | | |
| Basis ($/Mcf) (b) | (0.54 | ) | | (0.81 | ) | | (0.63 | ) | Basis ($/Mcf) (b) | $ | (0.47) | | | $ | (0.28) | |
| Cash settled basis swaps (not designated as hedges) ($/Mcf) | $ | 0.01 |
| | $ | 0.09 |
| | $ | 0.03 |
| Cash settled basis swaps (not designated as hedges) ($/Mcf) | 0.05 | | | (0.04) | |
| Average differential, including cash settled basis swaps ($/Mcf) | $ | (0.53 | ) | | $ | (0.72 | ) | | $ | (0.60 | ) | Average differential, including cash settled basis swaps ($/Mcf) | $ | (0.42) | | | $ | (0.32) | |
| | | | | | | | | | |
| Average adjusted price ($/Mcf) | $ | 2.83 |
| | $ | 1.97 |
| | $ | 2.31 |
| Average adjusted price ($/Mcf) | $ | 1.78 | | | $ | 2.44 | |
| Cash settled derivatives (cash flow hedges) ($/Mcf) | 0.01 |
| | 0.13 |
| | 0.47 |
| |
| Cash settled derivatives (not designated as hedges) ($/Mcf) | 0.05 |
| | 0.31 |
| | 0.28 |
| Cash settled derivatives (not designated as hedges) ($/Mcf) | 0.59 | | | 0.21 | |
| Average natural gas price, including cash settled derivatives ($/Mcf) | $ | 2.89 |
| | $ | 2.41 |
| | $ | 3.06 |
| Average natural gas price, including cash settled derivatives ($/Mcf) | $ | 2.37 | | | $ | 2.65 | |
| | | | | | | |
| Natural gas sales, including cash settled derivatives | $ | 2,237,234 |
| | $ | 1,649,831 |
| | $ | 1,671,562 |
| Natural gas sales, including cash settled derivatives | $ | 3,359,583 | | | $ | 3,805,977 | |
| | | | | | | |
| LIQUIDS | | | | | | LIQUIDS | | |
| NGLs (excluding ethane): | | | | | | |
| Natural gas liquids (NGLs), excluding ethane: | | Natural gas liquids (NGLs), excluding ethane: | |
| Sales volume (MMcfe) (c) | 74,060 |
| | 57,243 |
| | 51,530 |
| Sales volume (MMcfe) (c) | 44,702 | | | 44,082 | |
| Sales volume (Mbbls) | 12,343 |
| | 9,540 |
| | 8,588 |
| |
| Sales volume (Mbbl) | | Sales volume (Mbbl) | 7,451 | | | 7,348 | |
| Price ($/Bbl) | $ | 31.59 |
| | $ | 19.43 |
| | $ | 18.84 |
| Price ($/Bbl) | $ | 20.51 | | | $ | 23.63 | |
| Cash settled derivatives (not designated as hedges) ($/Bbl) | (0.69 | ) | | — |
| | — |
| Cash settled derivatives (not designated as hedges) ($/Bbl) | (0.12) | | | 2.19 | |
Average NGL price, including cash settled derivatives ($/Bbl)
| $ | 30.90 |
| | $ | 19.43 |
| | $ | 18.84 |
| |
| Average NGLs price, including cash settled derivatives ($/Bbl) | | Average NGLs price, including cash settled derivatives ($/Bbl) | $ | 20.39 | | | $ | 25.82 | |
| NGLs sales | $ | 381,327 |
| | $ | 185,405 |
| | $ | 161,775 |
| NGLs sales | $ | 151,877 | | | $ | 189,718 | |
| Ethane: | | | | | | Ethane: | |
| Sales volume (MMcfe) (c) | 33,432 |
| | 13,856 |
| | — |
| Sales volume (MMcfe) (c) | 29,489 | | | 23,748 | |
| Sales volume (Mbbls) | 5,572 |
| | 2,309 |
| | — |
| |
| Sales volume (Mbbl) | | Sales volume (Mbbl) | 4,914 | | | 3,957 | |
| Price ($/Bbl) | $ | 6.32 |
| | $ | 5.08 |
| | $ | — |
| Price ($/Bbl) | $ | 3.48 | | | $ | 6.16 | |
| Cash settled derivatives (not designated as hedges) ($/Bbl) | | Cash settled derivatives (not designated as hedges) ($/Bbl) | — | | | 1.02 | |
| Average Ethane price, including cash settled derivatives ($/Bbl) | | Average Ethane price, including cash settled derivatives ($/Bbl) | $ | 3.48 | | | $ | 7.18 | |
| Ethane sales | $ | 35,241 |
| | $ | 11,742 |
| | $ | — |
| Ethane sales | $ | 17,085 | | | $ | 28,414 | |
| Oil: | | | | | | Oil: | |
| Sales volume (MMcfe) (c) | 5,952 |
| | 4,373 |
| | 4,458 |
| Sales volume (MMcfe) (c) | 4,827 | | | 4,932 | |
| Sales volume (Mbbls) | 992 |
| | 729 |
| | 743 |
| |
| Sales volume (Mbbl) | | Sales volume (Mbbl) | 804 | | | 822 | |
| Price ($/Bbl) | $ | 40.70 |
| | $ | 34.73 |
| | $ | 38.70 |
| Price ($/Bbl) | $ | 25.57 | | | $ | 40.90 | |
| Oil sales | $ | 40,376 |
| | $ | 25,312 |
| | $ | 28,752 |
| Oil sales | $ | 20,574 | | | $ | 33,620 | |
| | | | | | | |
| Total liquids sales volume (MMcfe) (c) | 113,444 |
| | 75,472 |
| | 55,988 |
| Total liquids sales volume (MMcfe) (c) | 79,018 | | | 72,762 | |
| Total liquids sales volume (Mbbls) | 18,907 |
| | 12,578 |
| | 9,331 |
| |
| Total liquids sales volume (Mbbl) | | Total liquids sales volume (Mbbl) | 13,169 | | | 12,127 | |
| Total liquids sales | | Total liquids sales | $ | 189,536 | | | $ | 251,752 | |
| | | | | | | |
| Liquids sales | $ | 456,944 |
| | $ | 222,459 |
| | $ | 190,527 |
| |
| | | | | | | |
| TOTAL PRODUCTION | | | | | | |
| Total natural gas & liquids sales, including cash settled derivatives (d) | $ | 2,694,178 |
| | $ | 1,872,290 |
| | $ | 1,862,089 |
| |
| TOTAL | | TOTAL | |
| Total natural gas and liquids sales, including cash settled derivatives (d) | | Total natural gas and liquids sales, including cash settled derivatives (d) | $ | 3,549,119 | | | $ | 4,057,729 | |
| Total sales volume (MMcfe) | 887,520 |
| | 758,967 |
| | 603,082 |
| Total sales volume (MMcfe) | 1,497,792 | | | 1,507,896 | |
| | | | | | | |
| Average realized price ($/Mcfe) | $ | 3.04 |
| | $ | 2.47 |
| | $ | 3.09 |
| Average realized price ($/Mcfe) | $ | 2.37 | | | $ | 2.69 | |
(a) The Company’sOur volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/MMBtu)) was $3.11, $2.46$2.08 and $2.66$2.63 for the years ended December 31, 2017, 20162020 and 2015, respectively).2019, respectively.
(b)Basis represents the difference between the ultimate sales price for natural gas and the NYMEX natural gas price.
(c)NGLs, ethane and crude oil were converted to Mcfe at thea rate of six Mcfe per barrel for all periods.barrel.
(d) AlsoTotal natural gas and liquids sales, including cash settled derivatives, is also referred to in this report as EQT Production adjusted operating revenues, a non-GAAP supplemental financial measure.
(e) For the year ended December 31, 2017, EQT Production includes the results of production operations acquired in the Rice Merger for the period of November 13, 2017 through December 31, 2017.
Reconciliation of Non-GAAP Financial Measures Reconciliation
The table below reconciles EQT Production adjusted operating revenues, a non-GAAP supplemental financial measure, to EQT Productionwith total operating revenues, as reported under EQT Production Results of Operations, its most directly comparable financial measure calculated in accordance with GAAP. See Note 6 to the Consolidated Financial Statements for a reconciliation of EQT Production operating revenues to EQT Corporation total operating revenues as reported in the Statements of Consolidated Operations.
EQT Production adjustedAdjusted operating revenues (also referred to in this report as total natural gas &and liquids sales, including cash settled derivatives) is presented because it is an important measure used by the Company’s managementwe use to evaluate period-over-periodperiod-to-period comparisons of earnings trends. EQT Production adjustedAdjusted operating revenues as presented excludes the revenue impactimpacts of changes in the fair value of derivative instruments prior to settlement and the revenue impact of certain pipeline and net marketing services. Management utilizes EQT Productionservices and other. We use adjusted operating revenues to evaluate earnings trends because, as a result of the measure's exclusion of the often-volatile changes in the fair value of derivative instruments prior to settlement, the measure reflects only the impact of settled derivative contractscontracts. Net marketing services and thus does not impactother primarily includes the revenue from natural gas sales with the often volatile fluctuations in the fair valuecosts of, derivatives prior to settlement. EQT Production adjusted operating revenues also excludes "Pipeline and recoveries on, pipeline capacity releases. Because we consider net marketing services" because management considers these revenuesservices and other to be unrelated to the revenues for itsour natural gas and liquids production. "Pipeline and net marketing services" primarily includes revenues for gathering services provided to third parties as well as both the cost of and recoveries on third party pipeline capacity not used for EQT Production sales volumes. Management further believes that EQT Productionproduction activities, adjusted operating revenues as presentedexcludes net marketing services and other. We believe that adjusted operating revenues provides useful information to investors for evaluating period-over-periodperiod-to-period comparisons of earnings trends.
| | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | | 2019 |
| (Thousands, unless otherwise noted) |
| Total operating revenues | $ | 3,058,843 | | | $ | 4,416,484 | |
| Add (deduct): | | | |
| Gain on derivatives not designated as hedges | (400,214) | | | (616,634) | |
| Net cash settlements received on derivatives not designated as hedges | 897,190 | | | 246,639 | |
| Premiums received for derivatives that settled during the period | 1,630 | | | 19,676 | |
| Net marketing services and other | (8,330) | | | (8,436) | |
| Adjusted operating revenues, a non-GAAP financial measure | $ | 3,549,119 | | | $ | 4,057,729 | |
| | | |
| Total sales volumes (MMcfe) | 1,497,792 | | | 1,507,896 | |
| Average realized price ($/Mcfe) | $ | 2.37 | | | $ | 2.69 | |
Sales Volumes and Revenues
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | % |
| (Thousands, unless otherwise noted) |
| Sales volume by shale (MMcfe): | | | | | |
| Marcellus (a) | 1,314,801 | | | 1,270,352 | | | 3.5 | |
| Ohio Utica | 177,864 | | | 231,545 | | | (23.2) | |
| Other | 5,127 | | | 5,999 | | | (14.5) | |
| Total sales volumes (b) | 1,497,792 | | | 1,507,896 | | | (0.7) | |
| | | | | |
| Average daily sales volumes (MMcfe/d) | 4,092 | | | 4,131 | | | (0.9) | |
| | | | | |
| Operating revenues: | | | | | |
| Sales of natural gas, NGLs and oil | $ | 2,650,299 | | | $ | 3,791,414 | | | (30.1) | |
| Gain on derivatives not designated as hedges | 400,214 | | | 616,634 | | | (35.1) | |
| Net marketing services and other | 8,330 | | | 8,436 | | | (1.3) | |
| Total operating revenues | $ | 3,058,843 | | | $ | 4,416,484 | | | (30.7) | |
(a)Includes Upper Devonian wells.
(b)NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel.
Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil decreased for 2020 compared to 2019 due to a lower average realized price and lower sales volumes. Average realized price decreased due to lower NYMEX and unfavorable differential, partly offset by higher cash settled derivatives. For 2020 and 2019, we received $898.8 million and $266.3 million, respectively, of net cash settlements, including net premiums received, on derivatives not designated as hedges, which are included in average realized price but may not be included in operating revenues. Sales volumes for 2020 decreased compared
|
| | | | | | | | | | | |
| Calculation of EQT Production adjusted operating revenues | Years Ended December 31, |
| $ in thousands (unless noted) | 2017 | | 2016 | | 2015 |
| EQT Production total operating revenues | $ | 3,106,337 |
| | $ | 1,387,054 |
| | $ | 2,131,664 |
|
| (Deduct) add back: | | | | | |
| (Gain) loss on derivatives not designated as hedges | (390,021 | ) | | 248,991 |
| | (385,762 | ) |
| Net cash settlements received on derivatives not designated as hedges | 40,728 |
| | 279,425 |
| | 172,093 |
|
| Premiums received (paid) for derivatives that settled during the year | 2,132 |
| | (2,132 | ) | | (364 | ) |
| Pipeline and net marketing services | (64,998 | ) | | (41,048 | ) | | (55,542 | ) |
| EQT Production adjusted operating revenues, a non-GAAP financial measure | $ | 2,694,178 |
| | $ | 1,872,290 |
| | $ | 1,862,089 |
|
| | | | | | |
| Total sales volumes (MMcfe) | 887,520 |
| | 758,967 |
| | 603,082 |
|
| | | | | | |
| Average realized price ($/Mcfe) | $ | 3.04 |
| | $ | 2.47 |
| | $ | 3.09 |
|
Business Segment Resultsto 2019 due primarily to our strategic decisions to temporarily curtail production beginning in May 2020 and ending in November 2020 (the Strategic Production Curtailments) which resulted in a decrease to sales volumes of Operations
Business segment operating results from continuing operations are presentedapproximately 46 Bcfe. Sales volumes for 2020 also decreased compared to 2019 by 16 Bcfe as a result of the 2020 Divestitures (defined in the segment discussions and financial tables on the following pages. Operating segments are evaluated on their contributionNote 7 to the Company’s consolidated results based on operating income. Other income, interestConsolidated Financial Statements). These decreases were partly offset by operational efficiencies realized throughout the year from increased production up-time and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Unallocated expenses consist primarily of incentive compensation and administrative costs. In 2017, unallocated expenses also included the Rice Merger acquisition related expenses of $237.3 million, including $141.3 million of employee related expenses for payments to former Rice employees under the Merger Agreementpositively impacted sales volumes as well as investment banking, legalan increase of approximately 12 Bcfe due to the Chevron Acquisition.
Gain on derivatives not designated as hedges. For 2020, we recognized a gain on derivatives not designated as hedges of $400.2 million compared to $616.6 million for 2019. The gains for 2020 and other professional fees. In 2016, unallocated expenses also included2019 were related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices.
Operating Expenses
The following table presents information on our production-related operating expenses.
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | % |
| (Thousands, unless otherwise noted) |
| Operating expenses: | | | | | |
| Gathering | $ | 1,068,590 | | | $ | 1,038,646 | | | 2.9 | |
| Transmission | 506,668 | | | 588,302 | | | (13.9) | |
| Processing | 135,476 | | | 125,804 | | | 7.7 | |
| Lease operating expenses (LOE), excluding production taxes | 109,027 | | | 84,501 | | | 29.0 | |
| Production taxes | 46,376 | | | 69,284 | | | (33.1) | |
| Exploration | 5,484 | | | 7,223 | | | (24.1) | |
| Selling, general and administrative | 174,769 | | | 170,611 | | | 2.4 | |
| | | | | |
| Production depletion | $ | 1,375,542 | | | $ | 1,524,112 | | | (9.7) | |
| Other depreciation and depletion | 17,923 | | | 14,633 | | | 22.5 | |
| Total depreciation and depletion | $ | 1,393,465 | | | $ | 1,538,745 | | | (9.4) | |
| | | | | |
| Per Unit ($/Mcfe): | | | | | |
| Gathering | $ | 0.71 | | | $ | 0.69 | | | 2.9 | |
| Transmission | 0.34 | | | 0.39 | | | (12.8) | |
| Processing | 0.09 | | | 0.08 | | | 12.5 | |
| LOE, excluding production taxes | 0.07 | | | 0.06 | | | 16.7 | |
| Production taxes | 0.03 | | | 0.05 | | | (40.0) | |
| Exploration | — | | | — | | | — | |
| Selling, general and administrative | 0.12 | | | 0.11 | | | 9.1 | |
| Production depletion | 0.92 | | | 1.01 | | | (8.9) | |
Gathering. Gathering expense increased on an absolute and per Mcfe basis for 2020 compared to 2019 due to a higher gathering rate structure as a result of the Consolidated GGA (defined in Note 5 to the Consolidated Financial Statements), partly offset by lower gathered volumes as a result of the Strategic Production Curtailments. We expect to realize fee relief and a lower gathering rate structure from the Consolidated GGA beginning on the Mountain Valley Pipeline in-service date.
Transmission. Transmission expense decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to released capacity on, and credits received from, the Texas Eastern Transmission Pipeline, partly offset by higher costs associated with additional capacity on the Tennessee Gas Pipeline.
LOE. LOE increased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to higher repairs and maintenance costs as a result of our increased focus on optimizing production from currently producing wells as well as higher salt water disposal costs.
Production taxes. Production taxes decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to lower severance taxes and Pennsylvania impact fees as a result of lower commodity prices.
Depreciation and depletion. Production depletion decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to a lower annual depletion rate and lower volumes.
Amortization of intangible assets. Amortization of intangible assets for 2020 was $26.0 million compared to $35.9 million for 2019. The decrease was due primarily to the impairment of intangible assets recognized in the third quarter of 2019 as described below, which decreased the amortization rate. The intangible assets were fully amortized in November 2020.
Impairment/loss on sale/exchange of long-lived assets. During 2020, we recognized a loss on sale/exchange of long-lived assets of approximately $59.7$100.7 million, of which $61.6 million related to certain gathering assets sold to EQM in October 2016.
The Company has reported the components of each segment’s operating income2020 Asset Exchange Transactions (defined and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. EQT’s management believes that presentation of this information provides useful information to management and investors regarding the financial condition, operations and trends of each of EQT’s business segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest, income taxes and other income. In addition, management uses these measures for budget planning purposes. The Company has reconciled each segment’s operating income to the Company’s consolidated operating income and net incomediscussed in Note 6 to the Consolidated Financial Statements.
PriorStatements) and $39.1 million related to asset sales (described in Note 7 to the Rice Merger, the Company reported its results of operations through three business segments: EQT Production, EQT Gathering and EQT Transmission. These reporting segments reflected the Company's lines of business and were reported in the same manner in which the Company evaluated its operating performance through September 30, 2017. Following the Rice Merger, the Company adjusted its internal reporting structure to incorporate the newly acquired assets. The Company now conducts its business through five business segments: EQT Production, EQM Gathering (formerly known as EQT Gathering), EQM Transmission (formerly known as EQT Transmission), RMP Gathering and RMP Water. The EQT Production segment includes the Company’s production activities, including those acquired in the Rice Merger, the Company's marketing operations and certain gathering operations primarily supporting the Company's production activities, including the Rice retained gathering assets. The EQM Gathering segment and the EQM Transmission segment include all of the Company's assets and operations that are owned by EQM; therefore, the financial and operational disclosures related to EQM Gathering and EQM Transmission in this Annual Report on Form 10-K are the same as EQM’s disclosures in its Annual Report on Form 10-K for the year ended December 31, 2017. The RMP Gathering segment contains the Company's gathering assets that are owned by RMP. The RMP Water segment contains the Company's water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities owned by RMP. Following the Rice Merger, the financial and operational disclosures related to RMP Gathering and RMP Water will be the same as RMP’s successor disclosures in its Annual Report on Form 10-K for the year ended December 31, 2017.
EQT Production
|
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 (d) | | 2016 | | % change 2017 - 2016 | | 2015 | | % change 2016 - 2015 |
| OPERATIONAL DATA | | |
| | |
| | | | |
| | |
| | | | | | | | | | | |
| Sales volume detail (MMcfe): | | |
| | |
| | | | |
| | |
| Marcellus (a) | | 770,620 |
| | 660,146 |
| | 16.7 |
| | 505,102 |
| | 30.7 |
|
| Ohio Utica | | 24,266 |
| | 536 |
| | 4,427.2 |
| | 758 |
| | (29.3 | ) |
| Other | | 92,634 |
| | 98,285 |
| | (5.7 | ) | | 97,222 |
| | 1.1 |
|
| Total production sales volumes (b) | | 887,520 |
| | 758,967 |
| | 16.9 |
| | 603,082 |
| | 25.8 |
|
| | | | | | | | | | | |
| Average daily sales volumes (MMcfe/d) | | 2,432 |
| | 2,074 |
| | 17.3 |
| | 1,652 |
| | 25.5 |
|
| | | | | | | | | | | |
| Average realized price ($/Mcfe) | | $ | 3.04 |
| | $ | 2.47 |
| | 23.1 |
| | $ | 3.09 |
| | (20.1 | ) |
| | | | | | | | | | | |
| Gathering to EQM Gathering and RMP Gathering ($/Mcfe) | | $ | 0.47 |
| | $ | 0.48 |
| | (2.1 | ) | | $ | 0.51 |
| | (5.9 | ) |
| Transmission to EQM Transmission ($/Mcfe) | | $ | 0.20 |
| | $ | 0.20 |
| | — |
| | $ | 0.20 |
| | — |
|
| Third-party gathering and transmission ($/Mcfe) | | $ | 0.42 |
| | $ | 0.32 |
| | 31.3 |
| | $ | 0.29 |
| | 10.3 |
|
| Processing ($/Mcfe) | | $ | 0.20 |
| | $ | 0.16 |
| | 25.0 |
| | $ | 0.17 |
| | (5.9 | ) |
| Lease operating expenses (LOE), excluding production taxes ($/Mcfe) | | $ | 0.13 |
| | $ | 0.15 |
| | (13.3 | ) | | $ | 0.19 |
| | (21.1 | ) |
| Production taxes ($/Mcfe) | | $ | 0.08 |
| | $ | 0.08 |
| | — |
| | $ | 0.10 |
| | (20.0 | ) |
| Production depletion ($/Mcfe) | | $ | 1.04 |
| | $ | 1.06 |
| | (1.9 | ) | | $ | 1.18 |
| | (10.2 | ) |
| | | | | | | | | | | |
| Depreciation, depletion and amortization (DD&A) (thousands): | | | | |
| | | | |
| | |
| Production depletion | | $ | 924,430 |
| | $ | 803,883 |
| | 15.0 |
| | $ | 713,651 |
| | 12.6 |
|
| Other DD&A | | 57,673 |
| | 55,135 |
| | 4.6 |
| | 51,647 |
| | 6.8 |
|
| Total DD&A | | $ | 982,103 |
| | $ | 859,018 |
| | 14.3 |
| | $ | 765,298 |
| | 12.2 |
|
| | | | | | | | | | | |
| Capital expenditures (thousands) (c) | | $ | 2,430,094 |
| | $ | 2,073,907 |
| | 17.2 |
| | $ | 1,893,750 |
| | 9.5 |
|
| | | | | | | | | | | |
| FINANCIAL DATA (thousands) | | | | |
| | | | |
| | |
| | | | | | | | | | | |
| Revenues: | | | | | | | | | | |
| Sales of natural gas, oil and NGLs | | $ | 2,651,318 |
| | $ | 1,594,997 |
| | 66.2 |
| | $ | 1,690,360 |
| | (5.6 | ) |
| Pipeline and net marketing services | | 64,998 |
| | 41,048 |
| | 58.3 |
| | 55,542 |
| | (26.1 | ) |
| Gain (loss) on derivatives not designated as hedges | | 390,021 |
| | (248,991 | ) | | (256.6 | ) | | 385,762 |
| | (164.5 | ) |
| Total operating revenues | | 3,106,337 |
| | 1,387,054 |
| | 124.0 |
| | 2,131,664 |
| | (34.9 | ) |
| | | | | | | | | | | |
| Operating expenses: | | | | |
| | | | |
| | |
| Gathering | | 480,111 |
| | 413,758 |
| | 16.0 |
| | 330,562 |
| | 25.2 |
|
| Transmission | | 495,635 |
| | 341,569 |
| | 45.1 |
| | 268,368 |
| | 27.3 |
|
| Processing | | 179,538 |
| | 124,864 |
| | 43.8 |
| | 100,329 |
| | 24.5 |
|
| LOE, excluding production taxes | | 113,937 |
| | 112,509 |
| | 1.3 |
| | 116,527 |
| | (3.4 | ) |
| Production taxes | | 68,848 |
| | 62,317 |
| | 10.5 |
| | 61,408 |
| | 1.5 |
|
| Exploration | | 25,117 |
| | 13,410 |
| | 87.3 |
| | 61,970 |
| | (78.4 | ) |
| Selling, general and administrative (SG&A) | | 165,792 |
| | 180,426 |
| | (8.1 | ) | | 172,725 |
| | 4.5 |
|
| DD&A | | 982,103 |
| | 859,018 |
| | 14.3 |
| | 765,298 |
| | 12.2 |
|
| Amortization of intangible assets | | 5,540 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Impairment of long-lived assets | | — |
| | 6,939 |
| | (100.0 | ) | | 122,469 |
| | (94.3 | ) |
| Total operating expenses | | 2,516,621 |
| | 2,114,810 |
| | 19.0 |
| | 1,999,656 |
| | 5.8 |
|
| Gain on sale / exchange of assets | | — |
| | 8,025 |
| | (100.0 | ) | | — |
| | 100.0 |
|
| Operating income (loss) | | $ | 589,716 |
| | $ | (719,731 | ) | | (181.9 | ) | | $ | 132,008 |
| | (645.2 | ) |
| |
(a) | Includes Upper Devonian wells. |
| |
(b) | NGLs, ethane and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods. |
| |
(c) | Includes cash capital expenditures of $819.0 million, non-cash capital expenditures of $10.0 million and measurement period adjustments of $(14.3) million for acquisitions during the year ended December 31, 2017. Includes cash capital expenditures of $1,051.2 million and non-cash capital expenditures of $87.6 million related to acquisitions during the year ended December 31, 2016. See Note 10 to the Consolidated Financial Statements for additional information related to these transactions. |
| |
(d) | For the year ended December 31, 2017, the operating income for EQT Production includes the results of operations for the production operations and retained midstream operations acquired in the Rice Merger for the period of November 13, 2017 through December 31, 2017. See Note 2 for a discussion of the Rice Merger. |
Year Ended December 31, 2017 vs. December 31, 2016
EQT Production’s operating income totaled $589.7 million for 2017 compared to operating loss of $719.7 million for 2016. The $1,309.4 million increase was primarily due to gains on derivatives not designated as hedges for the year ended December 31, 2017 compared to losses on derivatives not designated as hedges for the year ended December 31, 2016, higher average realized price and increased sales volumes of produced natural gas and NGLs, partly offset by increased operating expenses. These variances include the impact of the operations of Rice for the period subsequent to the Rice Merger, which added approximately $165.6 million of operating income for the year ended December 31, 2017, including $114.6 million in gains on derivatives not designated as hedges.
Total operating revenues were $3,106.3 million for 2017 compared to $1,387.1 million for 2016. Sales of natural gas, oil and NGLs increased as a result of a higher average realized price and a 17% increase in production sales volumes in 2017. EQT Production received $40.7 million and $279.4 million of net cash settlements for derivatives not designated as hedges for the years ended December 31, 2017 and 2016, respectively, that are included in the average realized price but are not in GAAP operating revenues. Changes in fair market value of derivative instruments prior to settlement are recognized in gain (loss) on derivatives not designated as hedges. The increase in production sales volumes was primarily the result of recent acquisition activity, including the Rice Merger, as well as increased production from the 2015 and 2016 drilling programs, primarily in the Marcellus play, partially offset by the normal production decline in the Company's producing wells in 2017.
The $0.57 per Mcfe increase in the average realized price for the year ended December 31, 2017 was primarily due to the increase in the average NYMEX natural gas price net of cash settled derivatives of $0.29 per Mcf, an increase in the average natural gas differential of $0.19 per Mcf and an increase in liquids prices. The improvement in the average differential primarily related to more favorable basis partly offset by unfavorable cash settled basis swaps. During 2017, basis improved in the Appalachian Basin and at sales points reached through the Company’s transportation portfolio, particularly in the United States Northeast. In addition, the Company started flowing its produced volumes to its Rockies Express pipeline capacity and Texas Eastern Transmission Gulf Markets pipeline capacity in the fourth quarter of 2016, which resulted in a favorable impact to basis for the year ended December 31, 2017 compared to the year ended December 31, 2016.
Pipeline and net marketing services primarily includes gathering revenues for gathering services provided to third parties and both the cost of and recoveries on third party pipeline capacity not used to transport the Company’s produced volumes. The $24.0 million increase in these revenues primarily related to increased gathering revenues for services provided to third parties on gathering lines acquired from Rice in addition to costs, net of recoveries, for the Company’s Rockies Express Pipeline capacity in 2016.
EQT Production total operating revenues for the year ended December 31, 2017 included a $390.0 million gain on derivatives not designated as hedges compared to a $249.0 million loss on derivatives not designated as hedges for the year ended December 31, 2016. The gains for the year ended December 31, 2017 primarily related to increases in the fair market value of EQT Production’s NYMEX swaps due to decreased NYMEX prices, partly offset by decreases in the fair market value of its basis swaps due to increased basis prices.
Gathering expense increased due to increased affiliate and third party gathering capacity. The Rice Merger increased affiliate gathering expense as a result of volumes gathered by RMP Gathering which added approximately $21.0 million of expense for the post-Rice Merger period. In addition, EQT Production increased firm gathering capacity on the affiliate gathering systems owned by EQM Gathering in the fourth quarter of 2016 and 2017. The Company’s 2016 and 2017 acquisitions, excluding Rice, added third party gathering capacity and expense. Transmission expense increased due to increased third party capacity and increased firm contracts with affiliates incurred to move EQT Production’s natural gas out of the Appalachian Basin.Consolidated Financial Statements). During the fourth quarter of 2016, EQM's Ohio Valley Connector (OVC)2019, we recorded impairment of long-lived assets of $1,124.4 million, of which $1,035.7 million was placed into service and as a result, the Company started flowing its produced volumes to its Rockies Express pipeline capacity. Additionally, the Company's firm capacity on Rockies Express pipeline increasedassociated with our non-strategic assets located in the firstOhio Utica and $88.7 million was associated with our Pennsylvania and West Virginia Utica assets. The impairment was due primarily to depressed natural gas prices and changes in our development strategy. During the third quarter of 2017. Firm capacity acquired in connection with the Rice Merger also increased transmission expenses by approximately $24.2 million. In the fourth quarter2019, we recorded a loss on exchange of 2016, the Company started flowing its produced volumes to its Texas Eastern Transmission Gulf Markets pipeline capacity. Processing expense increased 44% as a resultlong-lived assets of increased processing capacity acquired through recent acquisitions and higher volumes processed, which is consistent with higher ethane and NGLs sales volumes of approximately 50% during 2017.
The increase in LOE was primarily due to higher salt water disposal costs. Production taxes increased as a result of higher market prices during the year ended December 31, 2017 in combination with an increase in the number of wells drilled in Pennsylvania and an increase in production volumes from recent acquisitions.
Exploration expense increased primarily due to expenses related to an exploratory well in a non-core operating area classified as a dry hole in 2017.
SG&A expense decreased primarily due to lower pension expense of $9.4$13.9 million related to the termination2019 Asset Exchange Transaction (defined and discussed in Note 6 to the Consolidated Financial Statements). See Note 1 to the Consolidated Financial Statements for a discussion of the EQT Corporation Retirement Plan for Employees in the second quarter of 2016, lower legal reserves in 2017, a reduction to the reserve for uncollectible accounts, and the absence of costs related to the consolidation of the Company’s Huron operations in 2016. This was partly offset by higher costs associated with recent acquisitions.2019 impairment test.
DD&A expense increased on higher production depletion as a result of higher produced volumes partly offset by a lower overall depletion rate in 2017. AmortizationImpairment of intangible assets increased as a result of intangible assets acquired in connection with the Rice Merger in 2017.
Impairment of long-lived assets decreased $6.9 million for the year ended December 31, 2017 compared to the year ended December 31, 2016. The 2016 impairment charge of $6.9 million primarily consisted of lease impairments on acreage that the Company did not intend to drill prior to expiration. The Company did not identify any such leases in 2017.
and other assets.During the fourth quarter of 2016, EQT Production sold a gathering system2020, we recognized impairment of $34.7 million, of which $22.8 million related to our assessment that primarily gathered gas for third parties for $75.0 million. In conjunction with this transaction, the Company realized a pre-tax gainfair values of $8.0certain of our right-of-use lease assets were less than their carrying values and $11.9 million which is included in gain on sale / exchangerelated to impairments of assets in the Statements of Consolidated Operations.
Year Ended December 31, 2016 vs. December 31, 2015
EQT Production’s operating loss totaled $719.7 million for 2016 compared to operating income of $132.0 million for 2015. The $851.7 million decrease in operating income was primarily due to a loss on derivatives not designated as hedges in 2016 compared to gains on derivatives not designated as hedges in 2015, a lower average realized price, increased operating expenses and decreased pipeline and net marketing services partly offset by increased sales volumes of produced natural gas and NGLs.
Total operating revenues were $1,387.1 million for 2016 compared to $2,131.7 million for 2015. Sales of natural gas, oil and NGLs decreasedcertain non-operating receivables as a result of a lower average realized price, partly offset by a 26% increase in production sales volumes in 2016. EQT Production received $279.4 million and $172.1expected credit losses. During the third quarter of 2019, we recognized impairment of $15.4 million of net cash settlementsintangible assets associated with non-compete agreements for derivatives not designated as hedgesformer Rice Energy Inc. executives who are now our employees.
Impairment and expiration of leases. Impairment and expiration of leases for the years ended December 31, 2016 and 2015, respectively, that are included2020 was $306.7 million compared to $556.4 million for 2019. The decrease was driven by increased lease expirations in the average realized price but are not in GAAP operating revenues. The increase in production sales volumes was primarily the result of increased production from the 2014 and 2015 drilling programs, primarily in the Marcellus play, partially offset by the normal production decline in the Company’s producing wells.
The $0.62 per Mcfe decrease in the average realized price for the year ended December 31, 2016 was primarily2019 due to the decreaseour change in the average NYMEX natural gas price netstrategic focus to core development opportunities as well as changes in market conditions.
Other operating expenses. Other operating expenses of cash settled derivatives$28.5 million in 2020 were related primarily to transactions, changes in legal reserves, including settlements and reorganization. Other operating expenses of $0.53 per Mcf and a decrease$199.4 million in the average
natural gas differential of $0.12 per Mcf. The decrease in the average differential2019 were related primarily related to lower basis partly offset by favorable cash settled basis swaps. While Appalachian Basin basis improved slightly for the year ended December 31, 2016 compared to the year ended December 31, 2015, basis in the United States Northeast was significantly lower, particularly in the
first quarter of 2016 compared to the first quarter of 2015,reorganization, due to reduced demand attributable to warmer than normal weather conditions. Additionally, the impact of changesreductions in natural gas prices on physical basis sales contracts and fixed price sales contracts reduced basis year over year. The Company started flowing EQT Production’s produced volumes to its Rockies Express pipeline capacity and Texas Eastern Transmission Gulf Markets pipeline capacity in the fourth quarter of 2016,workforce, which resulted in a favorable impact to basis in 2016.
Pipelinethe recognition of severance and net marketing services primarily includes gathering revenues for gathering services provided to third parties and both the cost of and recoveries on third party pipeline capacity not used to transport the Company’s produced volumes. The decrease in these revenues primarily related to reduced spreads on the Company’s Tennessee Gas Pipeline capacity.
EQT Production total operating revenues for the year ended December 31, 2016 included a $249.0 million loss on derivatives not designated as hedges compared to an $385.8 million gain on derivatives not designated as hedges for the year ended December 31, 2015. The losses for the year ended December 31, 2016 primarily related to unfavorableother termination benefits, changes in legal reserves, including settlements, contract terminations and the fair market value of EQT Production’s NYMEX swaps, partly offset by favorable changes in the fair market value of its basis swaps. During the year ended December 31, 2016, forward NYMEX prices increased while basis prices decreased.
Operating expenses totaled $2,114.8 million for 2016 compared to $1,999.7 million for 2015. The increase in operating
expenses primarily resulted from increases in DD&A, gathering, transmission and processing, partly offset by reductions in non-cash impairments of long-lived assets and exploration expense. Gathering expense increased due to increased affiliate firm capacity and volumetric charges and due to increased third party volumetric charges. Transmission expense increased as a result of higher third party costs incurred to move EQT Production’s natural gas out of the Appalachian Basin and increased affiliate firm capacity charges. Processing expenses increased due to higher production volumes.
The decrease in LOE was primarily due to lower salt water disposal costs as a result of increased recycling in the Marcellus Shale and certain operational cost savings in the Huron operations, partly offset by costs relatedproxy contest. See Note 1 to the consolidation of the Company’s Huron operations. Production taxes were essentially flat as a higher Pennsylvania impact fee and severance tax settlement were offset by lower unhedged sales prices, a favorable property tax settlement and the expiration of the West Virginia volume based tax in 2016. The state of West Virginia previously imposed a $0.047 per Mcf additional volume based severance tax that was terminated on July 1, 2016.Consolidated Financial Statements.
Exploration expense was lower primarily due to a decrease in lease expirations related to acreage that the Company does not intend to drill prior to expiration and expenses related to exploratory wells in 2015. SG&A expense increased due to higher litigation costs, a $9.4 million charge related to the termination of the EQT Corporation Retirement Plan for Employees incurred in 2016, an increase to the reserve for uncollectible accounts, and non-recurring costs related to the consolidation of the Company’s Huron operations and acquisition related expenses in 2016. These increases were partly offset by drilling program reduction charges in the Permian and Huron Basins in 2015, decreased personnel costs, decreased professional service costs and charges to write off expired right of ways options in 2015. The increase in depletion expense within DD&A expense was the result of higher produced volumes partly offset by a lower overall depletion rate in 2016. Depreciation expense within DD&A increased as a result of additional assets in service.
Impairment of long-lived assets decreased $115.5 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The 2016 impairment charge primarily consisted of lease impairments on acreage that the Company did not intend to drill prior to expiration. The 2015 impairment charge consisted of impairments of proved properties in the Permian Basin of Texas and impairments of proved properties in the Utica Shale of Ohio, as well as unproved property impairments and impairment of field level NGLs processing equipment that was not being used. The proved properties impairments in 2015 were a result of continued declines in commodity prices and insufficient recovery of hydrocarbons to support continued development. The 2016 and 2015 impairments related to the unproved properties resulted from operational decisions to focus near-term development activities in the Company's Marcellus, Upper Devonian and Utica acreage.
During the fourth quarter of 2016, EQT Production sold a gathering system that primarily gathered gas for third parties for $75.0 million. In conjunction with this transaction, the Company realized a pre-tax gain of $8.0 million, which is included in gain on sale / exchange of assets in the Statements of Consolidated Operations.
EQM Gathering
Results of Operations
|
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | % change 2017 - 2016 | | 2015 | | % change 2016 - 2015 |
| FINANCIAL DATA | | |
| | (Thousands, other than per day amounts) | | | |
|
| Firm reservation fee revenues | | $ | 407,355 |
| | $ | 339,237 |
| | 20.1 |
| | $ | 267,517 |
| | 26.8 |
|
| Volumetric based fee revenues: | | | | | | | | | | |
| Usage fees under firm contracts (a) | | 32,206 |
| | 38,408 |
| | (16.1 | ) | | 33,021 |
| | 16.3 |
|
| Usage fees under interruptible contracts | | 14,975 |
| | 19,849 |
| | (24.6 | ) | | 34,567 |
| | (42.6 | ) |
| Total volumetric based fee revenues | | 47,181 |
| | 58,257 |
| | (19.0 | ) | | 67,588 |
| | (13.8 | ) |
| Total operating revenues | | 454,536 |
| | 397,494 |
| | 14.4 |
| | 335,105 |
| | 18.6 |
|
| | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | |
| Operating and maintenance | | 43,235 |
| | 38,367 |
| | 12.7 |
| | 37,011 |
| | 3.7 |
|
| Selling, general and administrative | | 38,942 |
| | 39,678 |
| | (1.9 | ) | | 30,477 |
| | 30.2 |
|
| Depreciation and amortization | | 38,796 |
| | 30,422 |
| | 27.5 |
| | 24,360 |
| | 24.9 |
|
| Total operating expenses | | 120,973 |
| | 108,467 |
| | 11.5 |
| | 91,848 |
| | 18.1 |
|
| | | | | | | | | | | |
| Operating income | | $ | 333,563 |
| | $ | 289,027 |
| | 15.4 |
| | $ | 243,257 |
| | 18.8 |
|
| | | | | | | | | | | |
| OPERATIONAL DATA | | | | | | | | | | |
| Gathered volumes (BBtu per day): | | | | | | | | | | |
| Firm capacity reservation | | 1,826 |
| | 1,553 |
| | 17.6 |
| | 1,140 |
| | 36.2 |
|
| Volumetric based services (b) | | 361 |
| | 420 |
| | (14.0 | ) | | 485 |
| | (13.4 | ) |
| Total gathered volumes | | 2,187 |
| | 1,973 |
| | 10.8 |
| | 1,625 |
| | 21.4 |
|
| | | | | | | | | | | |
| Capital expenditures | | $ | 196,871 |
| | $ | 295,315 |
| | (33.3 | ) | | $ | 225,537 |
| | 30.9 |
|
| |
(a) | Includes fees on volumes gathered in excess of firm contracted capacity. |
| |
(b) | Includes volumes gathered under interruptible contracts and volumes gathered in excess of firm contracted capacity. |
Year Ended December 31, 2017 vs. December 31, 2016
Gathering revenues increased by $57.0 million driven by third party and affiliate production development in the Marcellus Shale. EQM Gathering increased firm reservation fee revenues in 2017 compared to 2016 as a result of third parties and affiliates contracting for additional firm gathering capacity, which increased firm gathering capacity by approximately 475 MMcf per day following the completion of the Range Resources header pipeline project and various affiliate wellhead gathering expansion projects. The decrease in usage fees under firm contracts was due to lower affiliate volumes in excess of firm contracted capacity. The decrease in usage fees under interruptible contracts was primarily due to the additional contracts for firm capacity.
Operating expenses increased by $12.5 million for the year ended December 31, 2017 compared to the year ended December 31, 2016. Operating and maintenance expense increased primarily as a result of higher personnel costs and increased property taxes. Selling, general and administrative expenses decreased primarily due to lower corporate allocations from the Company as a result of the Company’s shift in focus during 2017 from midstream drop-down transactions to upstream asset and corporate acquisition projects partly offset by increased miscellaneous administrative costs. Depreciation and amortization expense increased $8.4 million due to additional assets placed in-service including those associated with the Range Resources header pipeline project and various affiliate wellhead gathering expansion projects.
Year Ended December 31, 2016 vs. December 31, 2015
Gathering revenues increased by $62.4 million primarily as a result of higher affiliate and third party volumes gathered in
2016 compared to 2015, driven by production development in the Marcellus Shale. EQM Gathering increased firm reservation fee revenues in 2016 compared to 2015 as a result of affiliates and third parties contracting for additional capacity under firm contracts, which resulted in increased firm gathering capacity of approximately 300 MMcf per day following the completion of the Northern West Virginia gathering system (NWV Gathering) and Jupiter gathering system (Jupiter) expansion projects in the
fourth quarter of 2015. The decrease in usage fees under interruptible contracts was primarily due to these additional contracts for firm capacity.
Operating expenses increased by $16.6 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. Selling, general and administrative expenses increased as a result of higher allocations and personnel costs from EQT. The increase in depreciation and amortization expense resulted from additional assets placed in-service including those associated with the NWV Gathering and Jupiter expansion projects.
EQM Transmission
Results of Operations
|
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | % change 2017 - 2016 | | 2015 | | % change 2016 - 2015 |
| FINANCIAL DATA | | | | (Thousands, other than per day amounts) | | | |
| Firm reservation revenues | | $ | 348,193 |
| | $ | 277,816 |
| | 25.3 |
| | $ | 247,231 |
| | 12.4 |
|
| Volumetric based fee revenues: | | | | | | | | | | |
Usage fees under firm contracts(a) | | 13,743 |
| | 45,679 |
| | (69.9 | ) | | 42,646 |
| | 7.1 |
|
| Usage fees under interruptible contracts | | 17,624 |
| | 14,625 |
| | 20.5 |
| | 7,954 |
| | 83.9 |
|
| Total volumetric based fee revenues | | 31,367 |
| | 60,304 |
| | (48.0 | ) | | 50,600 |
| | 19.2 |
|
| Total operating revenues | | 379,560 |
| | 338,120 |
| | 12.3 |
| | 297,831 |
| | 13.5 |
|
| | | | | | | | | | | |
| Operating expenses: | | | | | | |
| | | | |
|
| Operating and maintenance | | 41,482 |
| | 34,846 |
| | 19.0 |
| | 33,092 |
| | 5.3 |
|
| Selling, general and administrative | | 32,244 |
| | 33,083 |
| | (2.5 | ) | | 31,425 |
| | 5.3 |
|
| Depreciation and amortization | | 58,689 |
| | 32,269 |
| | 81.9 |
| | 25,535 |
| | 26.4 |
|
| Total operating expenses | | 132,415 |
| | 100,198 |
| | 32.2 |
| | 90,052 |
| | 11.3 |
|
| | | | | | | | | | | |
| Operating income | | $ | 247,145 |
| | $ | 237,922 |
| | 3.9 |
| | $ | 207,779 |
| | 14.5 |
|
| | | | | | | | | | | |
| OPERATIONAL DATA | | |
| | |
| | |
| | |
| | |
|
| Transmission pipeline throughput (BBtu per day) | | | | | | | | | | |
| Firm capacity reservation | | 2,399 |
| | 1,651 |
| | 45.3 |
| | 1,841 |
| | (10.3 | ) |
Volumetric based services(b) | | 37 |
| | 430 |
| | (91.4 | ) | | 281 |
| | 53.0 |
|
| Total transmission pipeline throughput | | 2,436 |
| | 2,081 |
| | 17.1 |
| | 2,122 |
| | (1.9 | ) |
| | | | | | | | | | | |
| Average contracted firm transmission reservation commitments (BBtu per day) | | 3,627 |
| | 2,814 |
| | 28.9 |
| | 2,624 |
| | 7.2 |
|
| | | | | | | | | | | |
| Capital expenditures | | $ | 111,102 |
| | $ | 292,049 |
| | (62.0 | ) | | $ | 203,706 |
| | 43.4 |
|
| |
(a) | Includes commodity charges and fees on all volumes transported under firm contracts as well as transmission fees on volumes in excess of firm contracted capacity. |
| |
(b) | Includes volumes transported under interruptible contracts and volumes transported in excess of firm contracted capacity. |
Year Ended December 31, 2017 vs. December 31, 2016
Total operating revenues increased by $41.4 million. Firm reservation fee revenues increased due to affiliates and third parties contracting for additional firm capacity, primarily on the OVC, as well as higher contractual rates on existing contracts in the current year. The firm capacity on the OVC resulted in lower affiliate usage fees under firm contracts. The increase in usage fees under interruptible contracts includes increased storage and parking revenue, which does not have pipeline throughput associated with it, partly offset by reduced throughput on interruptible contracts.
Operating expenses increased by $32.2 million for the year ended December 31, 2017 compared to the year ended December 31, 2016. Operating and maintenance expense increased primarily due to property taxes on the OVC and higher personnel costs. Selling, general and administrative expenses decreased primarily due to lower corporate allocations from the Company as a result of the Company’s shift in focus during 2017 from midstream drop-down transactions to upstream asset and corporate acquisition projects. The increase in depreciation and amortization expense was the result of the OVC project placed in-service in the fourth quarter of 2016 and a non-cash charge to depreciation and amortization expense of $10.5 million related to the revaluation of differences between the regulatory and tax bases in EQM's regulated property, plant and equipment. The related regulatory liability will be amortized over the estimated useful life of the underlying property which is 43 years.
Year Ended December 31, 2016 vs. December 31, 2015
Total operating revenues increased by $40.3 million. Firm reservation revenues increased due to affiliates contracting for additional capacity under firm contracts, primarily on the OVC, as well as higher contractual rates on existing contracts in 2016. Higher usage fees under firm contracts were driven by an increase in affiliate volumes in excess of firm capacity associated with increased production development in the Marcellus Shale, partly offset by lower usage fees from third party producers which is reflected in reduced firm capacity reservation throughput for the year ended December 31, 2016 compared to the year ended December 31, 2015. These volumes also decreased as a result of warmer weather in the first quarter of 2016. This decrease in transported volumes did not have a significant impact on firm reservation fee revenues. Usage fees under interruptible contracts for the year ended December 31, 2016 increased as a result of higher third party volumes transported or stored on an interruptible basis.
Operating expenses increased by $10.1 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The increase in operating and maintenance expense resulted primarily from higher repairs and maintenance expenses associated with increased throughput. Selling, general and administrative expenses increased primarily as a result of higher allocations and personnel costs from EQT. The increase in depreciation and amortization expense was primarily a result of higher depreciation on the increased investment in transmission infrastructure, including those associated with the OVC and the AVC facilities.
RMP Gathering
Results of Operations
|
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 (a) | | 2016 | | % change 2017 - 2016 | | 2015 | | % change 2016 - 2015 |
| FINANCIAL DATA | | (Thousands, other than per day amounts) |
| Gathering revenues: | | | | | | | | | | |
| Affiliate | | $ | 26,242 |
| | $ | — |
| | 100.0 |
| | $ | — |
| | — |
|
| Third-party | | 19 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Total gathering revenues | | 26,261 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| | | | | | | | | | | |
| Compression revenues: | | | | | | | | | | |
| Affiliate | | 4,343 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Third-party | | 10 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Total compression revenues | | 4,353 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Total operating revenues | | 30,614 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | |
| Operation and maintenance expense | | 1,584 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| General and administrative expense | | 3,265 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Depreciation expense | | 3,965 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Total operating expenses | | 8,814 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| | | | | | | | | | | |
| Operating income (loss) | | $ | 21,800 |
| | $ | — |
| | 100.0 |
| | $ | — |
| | — |
|
| | | | | | | | | | | |
| OPERATIONAL DATA | | | | | | | | | | |
| Gathered volumes (BBtu/d): | | 1,547 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| | |
| | | | | | | | |
| Compression volumes (BBtu/d): | | 1,155 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| | | | | | | | | | | |
| Capital expenditures | | $ | 28,320 |
| | $ | — |
| | 100.0 |
| | $ | — |
| | — |
|
(a) This table sets forth selected financial and operational data for RMP Gathering for the period November 13, 2017 through December 31, 2017, as the Company acquired RMP Gathering on November 13, 2017 as part of the Rice Merger.
The majority of RMP Gathering revenues are from contracts with EQT Production to gather gas in Washington and Greene Counties, Pennsylvania. RMP Gathering provides all services under long-term contracts that are supported in most cases by acreage dedications. RMP Gathering charges separate rates for gathering and compression services based on the actual volumes gathered and compressed. During the period from November 13, 2017 through December 31, 2017, operating expenses are composed of customary expenses for a gathering business.
RMP Water
Results of Operations
|
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 (a) | | 2016 | | % change 2017 - 2016 | | 2015 | | % change 2016 - 2015 |
| FINANCIAL DATA | | (Thousands, other than per day amounts) |
| Operating revenues: | | | | | | | | | | |
| Affiliate | | $ | 13,549 |
| | $ | — |
| | 100.0 |
| | $ | — |
| | — |
|
| Third-party | | 56 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Total operating revenues | | 13,605 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | |
| Operation and maintenance expense | | 5,598 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| General and administrative expense | | 347 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Depreciation expense | | 3,515 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| Total operating expenses | | 9,460 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| | | | | | | | | | | |
| Operating income (loss) | | $ | 4,145 |
| | $ | — |
| | 100.0 |
| | $ | — |
| | — |
|
| | | | | | | | | | | |
| OPERATIONAL DATA | | | | | | | | | | |
| Water services volumes (in MMgal): | | 226 |
| | — |
| | 100.0 |
| | — |
| | — |
|
| | | | | | | | | | | |
| Capital expenditures | | $ | 6,233 |
| | $ | — |
| | 100.0 |
| | $ | — |
| | — |
|
(a) This table sets forth selected financial and operational data for RMP Water for the period November 13, 2017 through December 31, 2017, as the Company acquired RMP Water on November 13, 2017 as part of the Rice Merger.
RMP Water provides fresh water for well completions operations in the Marcellus and Utica Shales and collects and recycles or disposes of flowback and produced water. The majority of RMP Water's services are provided to EQT Production. RMP Water offers its services on a volumetric basis, supported by an acreage dedication from EQT Production for certain drilling areas. RMP Water charges customers a fee per gallon of water; this fee is tiered and thus is lower on a per gallon basis once the customer meets certain volumetric thresholds. During the period from November 13, 2017 through December 31, 2017, operating expenses are composed of customary expenses for a water business.
Other Income Statement Items
Other IncomeGain on Equitrans Share Exchange. During the first quarter of 2020, we recognized a gain on the Equitrans Share Exchange as described in Note 5 to the Consolidated Financial Statements.
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Other income | | $ | 24,955 |
| | $ | 31,693 |
| | $ | 9,953 |
|
ForLoss on investment in Equitrans Midstream Corporation. Our investment in Equitrans Midstream is recorded at fair value by multiplying the years endedclosing stock price of Equitrans Midstream's common stock by the number of shares of Equitrans Midstream's common stock that we own. Changes in fair value are recorded in loss on investment in Equitrans Midstream Corporation in the Statements of Consolidated Operations. Our investment in Equitrans Midstream fluctuates with changes in Equitrans Midstream's stock price, which was $8.04 and $13.36 as of December 31, 2017, 20162020 and 2015,2019, respectively. Note, the Company recorded equity in earnings of nonconsolidated investments of $22.2 million, $9.9 million and $2.6 million, respectively, related to EQM's portioneffect of the MVP Joint Venture's AFUDCsale of 50% of our shares of Equitrans Midstream's common stock was recorded as a reduction to the investment in Equitrans Midstream in conjunction with our recognition of the gain on the MVP project.
For the years ended December 31, 2017, 2016 and 2015, the Company recorded AFUDC of $5.1 million, $19.4 million and $6.3 million, respectively. The changes in AFUDC were mainly attributableEquitrans Share Exchange. See Note 5 to the timingConsolidated Financial Statements.
Dividend and other income. The decrease in 2020 as compared to 2019 is due primarily to lower dividends received from our investment in Equitrans Midstream driven by the decrease in the number of spending on the OVC project.shares of Equitrans Midstream's common stock that we own.
The Company initiated its investments in trading securities in 2016 to enhance returns on a portion of its significant cash balance at that time.Trading securities consist of liquid debt securities that are carried at fair value. For the years ended December 31, 2017 and 2016 the Company recorded realized losses of $2.6 million and unrealized gains of $1.5 million, respectively, on these debt securities. As of March 31, 2017, the Company closed its positions on all trading securities.
Loss on Debt Extinguishment
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Loss on debt extinguishment | | $ | 12,641 |
| | $ | — |
| | $ | — |
|
For the year ended December 31, 2017, the Company recordeddebt extinguishment. During 2020, we recognized a loss on debt extinguishment of $12.6 million in connection with the early extinguishment on November 3, 2017 of the $200 million aggregate principal amount 5.15% Senior Notes due 2018 and $500 million aggregate principal amount 6.50% Senior Notes due 2018. The loss consists of $12.2 million paid in excess of par in order to extinguish the debt prior to maturity and $0.4 million in non-cash expenses related to the write-off of unamortized financing costs and discounts.
Interest Expense
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | |
| | (Thousands) | | |
|
| Interest expense | | $ | 202,772 |
| | $ | 147,920 |
| | $ | 146,531 |
|
Interest expense increased $54.9 million in 2017 compared to 2016 primarily driven by $23.6 million of interest incurred on Senior Notes issued in October 2017, $17.4 million of interest incurred on EQM's Senior Notes issued in November 2016, $8.0 million of expense related to the bridge financing commitment for the Rice Merger and $6.0 million of interest incurred on credit facility borrowings partly offset by a $7.0 million decrease due to the early extinguishment of EQT Senior Notes.
Interest expense increased $1.4 million in 2016 compared to 2015. Decreased capitalized interest of $13.3 million and additional interest expense of approximately $3.3 million related to EQM's $500 million 4.125% Senior Notes issued during the fourth quarter of 2016 were mostly offset by higher interest income earned on short-term investments of $6.7 million, lower interest expense resulting from the Company's repayment of $160.0 millionall or a portion of debt that maturedour 4.875% senior notes, 2.50% senior notes, 3.00% senior notes, floating rate notes and Term Loan Facility (defined and discussed in the fourth quarter of 2015, and lower
EQM revolver fees.
The weighted average annual interest rates on the weighted average principal outstanding of the Company’s Senior Notes, excluding EQM’s Senior Notes, were 5.6%, 6.5%, and 6.5% for 2017, 2016 and 2015, respectively. The weighted average annual interest rates on EQM’s Senior Notes were 4.1% for 2017 and 4.0% for each of 2016 and 2015.
See Note 1410 to the Consolidated Financial Statements for discussion of the borrowings and weighted average interest rates for EQT's, EQM's and RMP's credit facilities.
Income Taxes
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Income tax (benefit) expense | | $ | (1,115,619 | ) | | $ | (263,464 | ) | | $ | 104,675 |
|
On December 22, 2017, the U.S. Congress enacted the law known as the Tax Cuts and Jobs Act of 2017 (the Tax Reform Legislation), which made significant changes to U.S. federal income tax law, including lowering the federal corporate tax rate to 21% from 35% beginning January 1, 2018. As a result of the change in the corporate tax rate, the Company recorded a deferred tax benefit of $1.2 billion during the year ended December 31, 2017 to revalue its existing net deferred tax liabilities to the lower rate.
For federal income tax purposes, the Company may deduct a portion of its drilling costs as intangible drilling costs (IDCs) in the year incurred. IDCs, however, have historically been limited for purposes of the alternative minimum tax (AMT) and this has resulted in the Company paying AMT even when generating or utilizing a net operating loss carryforward (NOL) to offset regular taxable income.
The Tax Reform Legislation also repealed the AMT for tax years beginning January 1, 2018 and provides that existing AMT credit carryforwards can be utilized to offset current federal tax liability in tax years 2018 through 2020. In addition, 50% of any unused AMT credit carryforwards can be refunded during these years with any remaining AMT credit carryforward being fully refunded in 2021. The Company had approximately $435 million of AMT credit carryforward as of December 31, 2017. In addition, the Tax Reform Legislation preserved deductibility of IDCs, and provides for 100% bonus depreciation on some tangible property expenditures through 2022.
The Tax Reform Legislation contains several other provisions, such as limiting the utilization of NOLs generated after December 31, 2017 that are carried into future years to 80% of taxable income and limitations on the deductibility of interest expense, which are not expected to have a material effect on the Company's results of operations. As of December 31, 2017, the Company has not completed its accounting for the effects of the Tax Reform Legislation, but has recorded provisional amounts for the revaluing of net deferred tax liabilities as well as the state income tax effects related to the Tax Reform Legislation. The Company also considered whether existing deferred tax amounts will be recovered in future periods under this legislation. However, the Company is still analyzing certain aspects of the Tax Reform Legislation and refining calculations, which could potentially impact the measurement of these balances or potentially give rise to new deferred tax amounts. The Company will refine its estimates to incorporate new or better information as it comes available through the filing date of its 2017 U.S. income tax returns in the fourth quarter of 2018.
All of EQGP's, RMP's and Strike Force Midstream's income is included in the Company's pre-tax income (loss)Statements). However, the Company is not required to record income tax expense with respect to the portions of EQGP's and RMP's income allocated to the noncontrolling public limited partners of EQGP, EQM, and RMP or to the minority owner of Strike Force Midstream, which reduces the Company's effective tax rate in periods when the Company has consolidated pre-tax income and increases the Company's effective tax rate in periods when the Company has consolidated pre-tax loss.
For 2017 and 2016, the Company generated a federal taxable loss and the Company paid AMT in 2016. The federal and AMT NOLs generated by the taxable losses for 2017 and 2016 will be carried back to 2015 and 2014 to generate a tax refund from 2015 and an increase in AMT credit carryforwards for those years. The Company paid federal income tax in 2015 as a result of tax gains related to EQGP's IPO and the sale of NWV Gathering to EQM during that year.
See Note 1110 to the Consolidated Financial StatementsStatements.
Interest expense. Interest expense increased for further discussion2020 compared to 2019 due to increased interest incurred on new debt issued in 2020 as well as interest incurred on letters of the Company’s income tax (benefit) expense, including a reconciliation between income tax expense calculated at the current federal statutory rate and the effective tax rate reflectedcredit issued in the Company's financial statements for each of the years ended December 31, 2017, 2016 and 2015.
Net Income Attributable to Noncontrolling Interests
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Net income attributable to noncontrolling interests | | $ | 349,613 |
| | $ | 321,920 |
| | $ | 236,715 |
|
The increase in net income attributable to noncontrolling interests for the year ended December 31, 2017 was the result of higher net income at EQM and noncontrolling interests in RMP and Strike Force Midstream as a result of the Rice Merger. The increase in net income attributable to noncontrolling interests for the year ended December 31, 2016 was primarily the result of increased net income at EQM, increased ownership of EQM common units2020. These increases were partly offset by third parties and EQGP's IPO in 2015.
Outlook
The Company’s board of directors has formed a committee to evaluate options for addressing the Company’s sum-of-the-parts discount. The board will announce a decision by the end of March, 2018, after considering the committee’s recommendation.
The Company is committed to profitably and safely developing its Appalachian Basin natural gas and NGL reserves through environmentally responsible, cost-effective and technologically advanced horizontal drilling. The Company believes the long-term outlook for its business is favorablelower interest incurred due to the Company’s substantial resource base, low cost structure, financial strength, risk management, including its commodity hedging strategy,repayment of all or a portion of our 8.125% senior notes, 4.875% senior notes, floating rate notes and disciplined investment of capital. The Company believes2.50% senior notes and decreased borrowings on our credit facility. See Note 10 to the combination of these factors provide it with an opportunity to exploit and develop its positions and maximize efficiency through economies of scale in its strategic operating area.Consolidated Financial Statements.
The Company monitors currentadjusted interest rate under the Adjustable Rate Notes (defined and expected market conditions, includingdiscussed in Note 10 to the commodity price environment, and its liquidity needs and may adjust its capital investment plan accordingly. While the tactics continue to evolve based on market conditions, the Company periodically considers arrangements to monetize the value of certain mature assets for re-deployment into the highest value development opportunities. Upon the closingConsolidated Financial Statements) cannot exceed 2% of the Rice Merger,original interest rate first set forth on the Company’s consolidation goals were largely met andface of the Company plansAdjustable Rate Notes; however, if our credit ratings improve, the interest rate under the Adjustable Rate Notes could be reduced to focusas low as the original interest rate set forth on integrating the Rice assets and realizing higher returns through longer laterals and achieving an even lower operating cost structure. The Company will also continue to pursue tactical acquisitionsface of fill-in acreage to extend laterals and has announced its intention to sell the Rice retained midstream assets to EQM through one or more drop-down transactions. Adjustable Rate Notes.
EQT Production expects to spend approximately $2.2 billion for well development (primarily drilling and completion) in 2018, which is expected to support the drilling of approximately 195 gross wells, including 134 Marcellus wells, 16 Upper Devonian wells and 45 Ohio Utica wells. The Company also intends to spend approximately $0.2 billion for acreage fill-ins, bolt-on leasing and other items. Estimated sales volumes are expected to be 1,520 - 1,560 Bcfe for 2018.
The 2018 drilling program is expected to support a 15% increase in production sales volume in 2019 over our 2018 expected sales volumes with total NGLs volumes expected to be 12,300 - 12,600 Mbbls. To support continued growth in production, the Company plans to invest approximately $1.5 billion on midstream infrastructure through EQM in 2018, including capital contributionsIncome tax benefit. See Note 9 to the MVP Joint Venture of $1.1 billion. RMP investments in organic projects are expected to total approximately $260 million in 2018, including $215 million for gathering and compression and $45 million for water infrastructure.Consolidated Financial Statements.
The 2018 capital investment plan for EQT Production is expected to be funded by cash generated from operations and cash on hand. EQM's available sources of liquidity include cash on hand and generated from operations, borrowings under its credit facilities, debt offerings and issuances of additional EQM partnership interests. RMP's 2018 capital investment plan is expected to be funded by cash generated from operations and borrowings under its credit facility.
The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop its reserves of, natural gas and NGLs. Due to the volatility of commodity prices, the Company is unable to predict future potential movements in the market prices for natural gas, including Appalachian and other market point basis, and NGLs and thus cannot predict the ultimate impact of prices on its operations.
The Company's 2018 capital expenditure forecast for well development is 59% higher than its 2017 well development spending. Changes in natural gas, NGLs and oil prices could affect, among other things, the Company's development plans, which would increase or decrease the pace of the development and the level of the Company's reserves, as well as the Company's revenues, earnings or liquidity. Lower prices could also result in non-cash impairments in the book value of the Company’s oil and gas
properties, goodwill or other long lived intangible assets or downward adjustments to the Company’s estimated proved reserves. Any such impairment and/or downward adjustment to the Company’s estimated reserves could potentially be material to the Company.
Impairment of Oil and Gas Properties and Goodwill
See “Critical"Critical Accounting Policies and Estimates”Estimates" and Note 1 to the Consolidated Financial Statements for a discussion of the Company’sour accounting policies and significant assumptions related to impairment of the Company’sour oil and gas properties. Due to declines in the five-year NYMEX forward strip prices during 2015 and into 2016, the Company determined that indicators of potential impairment existed for certain of the Company’s proved oil and gas properties in those years. No indicators of impairment were identified as of December 31, 2017. Although the Company did not have indicators of impairment or record an impairment on its oil and gas producing properties during 2017, all other things being equal, a further decline in the average five-year NYMEX forward strip price in a future period may cause the Company to recognize impairments on non-core assets, including the Company's assets in the Huron play, which had a carrying value of approximately $3 billion at December 31, 2017.
See “Critical Accounting Policies and Estimates” for a discussion of the Company’s accounting policies and significant assumptions related to evaluating the Company’s goodwill for impairment. The Company evaluated goodwill for impairment at December 31, 2017 and determined there was no indicator of impairment. We use a combination of the income and market approach to estimate the fair value of a reporting unit. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results as well as other assumptions such as movement in the Company's stock price, weighted-average cost of capital, terminal growth rates and industry multiples. Although we believe the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different estimates and assumptions could materially impact the calculated fair value of the reporting units. Additionally, future results could differ from our current estimates and assumptions. Any potential change in such estimates and assumptions would have an impact on the results of operations and financial position. Due to the uncertainty inherent in, and the interdependence of, the assumptions of underlying assets and goodwill impairment determinations, the Company cannot predict if future impairment charges will be recognized and, if so, an estimate of the impairment charges that would be recorded in any future period.
See “Naturalalso Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our non-core assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or impairment of goodwill and other long lived intangible assetsadditional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods.” under Item 1A, “Risk Factors.”"
Capital Resources and Liquidity
The Company’s primary sourcesAlthough we cannot provide any assurance, we believe cash flows from operating activities and availability under our credit facility should be sufficient to meet our cash requirements inclusive of, cashbut not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the next twelve months and, based on current expectations, for the year ended December 31, 2017 were proceeds from the 2017 Notes Offering (defined in Note 15long-term.
Credit Facility
We primarily use borrowings under our credit facility to the Consolidated Financial Statements), borrowings on credit facilitiesfund working capital needs, timing differences between capital expenditures and other cash uses and cash flows from operating activities, whilemargin deposit requirements on our derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. See Note 10 to the primary usesConsolidated Financial Statements for further discussion of our credit facility.
Known Contractual and Other Obligations; Planned Capital Expenditures
Purchase obligations. We have commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines, some of which extend up to 20 years or longer. We have entered into agreements to release some of our capacity under these long-term contracts. We also have commitments for processing capacity in order to extract heavier liquid hydrocarbons from the natural gas stream. Aggregate future payments for these items as of December 31, 2020 were $24.8 billion, composed of $1.3 billion in 2021, $1.7 billion in 2022, $1.8 billion in 2023, $1.9 billion in 2024, $1.8 billion in 2025 and $16.3 billion primarily in 2026 through 2042. We also have commitments to purchase equipment, materials, frac sand for use as a proppant in our hydraulic fracturing operations and minimum volume commitments associated with certain water agreements. As of December 31, 2020, future commitments under these contracts were $96.5 million in 2021 and $14.3 million in 2022.
Contractual Commitments. We have contractual commitments under our debt agreements including interest payments and principal repayments. See Note 10 to the Consolidated Financial Statements for further discussion including the timing of principal repayments.
Unrecognized Tax Benefits. As discussed in Note 9 to the Consolidated Financial Statements, we had a total reserve for unrecognized tax benefits at December 31, 2020 of $181.2 million, of which $90.3 million is offset against deferred tax assets for general business tax credit carryforwards and NOLs. We are currently unable to make reasonably reliable estimates of the period of cash were for redemptions and repaymentssettlement of Rice's Senior Notes and credit facilitiesthese potential liabilities with taxing authorities.
Planned Capital Expenditures. In 2021, we expect to spend approximately $1.1 to $1.2 billion in connection with the closing of the Rice Merger,total capital expenditures, excluding amounts attributable to noncontrolling interests. Because we are the cashoperator of a high percentage of our acreage, the amount and timing of these capital expenditures are largely discretionary. We could choose to defer a portion of these planned 2021 capital expenditures depending on a variety of factors, including prevailing and anticipated prices for natural gas, NGLs and oil; the Merger Consideration foravailability of necessary equipment, infrastructure and capital; the Rice Merger,receipt and redemptionstiming of Company Senior Notes.required regulatory permits and approvals; and drilling, completion and acquisition costs.
Operating Activities
The Company’s netNet cash provided by operating activities increased $573.4was $1,538 million from full year 2016for 2020 compared to full year 2017.$1,852 million for 2019. The increase indecrease was due primarily to lower cash flows provided by operating activities was primarily driven by higher operating income for which contributing factors are discussed in the "Consolidated Results of Operations"revenues and "Business Segment Results of Operations" sections herein and theunfavorable timing of working capital payments, between the two periods, partly offset by lowerincreased cash settlements received on derivatives not designated as hedges.hedges, income tax refunds, plus interest, received of $440 million during 2020 and lower cash operating expenses.
The Company’s net cash provided by operating activities decreased by $152.6 million from full year 2015 to full year 2016. The decrease in cash flows provided by operating activities was primarily the result of a lower commodity price and higher operating expenses, partly offset by higher production sales volumes, cash settlements on derivatives not designated as hedges, decreases in cash paid for income taxes and the timing of payments between periods.
The Company'sOur cash flows from operating activities will be impactedare affected by future movements in the market price for commodities. The Company isWe are unable to predict these future pricesuch movements outside of the current market view as reflected in forward strip pricing. Refer to "NaturalItem 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect uponon our revenue, profitability, future rate of growth, liquidity and financial position." under Item 1A, "Risk Factors" for further information.
Investing Activities
Cash flowsNet cash used in investing activities totaled $4,127.1was $1,556 million for 2017 as2020 compared to $2,961.5$1,601 million for 2016.2019. The $1,165.6 million increasedecrease was primarily due to investment in the Rice Merger, an increase inlower capital expenditures for drillingas a result of our change in strategic focus from production growth to capital efficiency as well as cash received from asset sales and completions spending, and higher capital contributions to the MVP Joint Venture,Equitrans Share Exchange. The decrease was partly offset by a decreasecash paid for acquisitions as described in capital expenditures for other property acquisitions, cash received from the sale of trading securities and lower EQMNote 6.
The following table summarizes our capital expenditures.
| | | | | | | | | | | |
| | Years Ended December 31, |
| 2020 | | 2019 |
| (Millions) |
| Reserve development | $ | 839 | | | $ | 1,377 | |
| Land and lease (a) | 121 | | | 195 | |
| Capitalized overhead | 51 | | | 77 | |
| Capitalized interest | 17 | | | 24 | |
| Other production infrastructure | 40 | | | 97 | |
| Other corporate items | 11 | | | 3 | |
| Total capital expenditures | 1,079 | | | 1,773 | |
| (Deduct) add non-cash items (b) | (37) | | | (171) | |
| Total cash capital expenditures | $ | 1,042 | | | $ | 1,602 | |
On November 13, 2017, in conjunction with the Rice Merger, each share of the common stock, par value $0.01 per share, of Rice (the Rice Common Stock) issued and outstanding immediately prior
(a)Capital expenditures attributable to the Effective Time was converted into the right to receive 0.37 (the Exchange Ratio) of a share of the common stock, no par value, of the Company (Company Common Stock) and $5.30 in cash (collectively, the Merger Consideration). The aggregate Merger Consideration consisted of approximately 91 million shares of Company Common Stock and approximately $1.6 billion in cash (net of cash acquired and inclusive of amounts payable to employees of Rice who did not continue with the Company following the Effective Time). See Note 2 to the Consolidated Financial Statements for further discussion of the Rice Merger.
Cash flows used in investing activities totaled $2,961.5noncontrolling interests were $4.9 million for 2016 as compared to $2,525.6 million for 2015. The $435.9 million increase was primarily due to an increase in capital expenditures for acquisitions of $1,051.2 million and investments in trading securities of $288.8 million, partly offset by a reduction in the drilling and completions capital expenditures. During 2016, the Company invested in trading securities, which consist of liquid debt securities carried at fair value, to maximize returns. The Company also placed $75.0 million of the proceeds received from the sale of a gathering system into restricted cash for a potential like-kind exchange for tax purposes.year ended December 31, 2020.
Capital Expenditures
(in millions)
|
| | | | | | | | | | | |
| | 2017 Actual | | 2016 Actual | | 2015 Actual |
| Well development (primarily drilling and completion) | 1,385 |
| | 783 |
| | 1,670 |
|
| Property acquisitions | 1,007 |
| | 1,284 |
| | 182 |
|
| Other Production infrastructure | 38 |
| | 7 |
| | 41 |
|
| EQM Gathering | 197 |
| | 295 |
| | 226 |
|
| EQM Transmission | 111 |
| | 292 |
| | 204 |
|
| RMP Gathering | 28 |
| | — |
| | — |
|
| RMP Water | 6 |
| | — |
| | — |
|
| Other corporate items | 7 |
| | 7 |
| | 21 |
|
| Total | $ | 2,779 |
| | $ | 2,668 |
| | $ | 2,344 |
|
| Less: non-cash * | 9 |
| | 77 |
| | (90 | ) |
| Total cash capital expenditures | $ | 2,770 |
| | $ | 2,591 |
| | $ | 2,434 |
|
*(b)Represents the net impact of non-cash capital expenditures, including capitalized non-cash stock-basedshare-based compensation expensecosts, the effect of timing of receivables from working interest partners and accruals.accrued capital expenditures. The impact of accrued capital expenditures includes the reversal of the prior period accrual as well as the current period estimate, both of which are non-cash items. The year ended December 31, 2017 included $10.0 million of non-cash capital expenditures related to 2017 acquisitions and $(14.3) million of measurement period adjustments for 2016 acquisitions. The year ended December 31, 2016 included $87.6 million of non-cash capital expenditures related to 2016 acquisitions.estimate.
The Company has forecast a 2018 capital expenditure spending plan of approximately $2.4 billion for EQT Production, which includes $2.2 billion for well development (primarily drilling and completion) and $0.2 billion for acreage fill-ins, bolt-on leasing and other items. The Company has also forecast an EQM 2018 capital expenditure spending plan of approximately $1.5 billion on midstream infrastructure including capital contributions to MVP and an RMP 2018 capital expenditure spending plan of approximately $260 million for gathering infrastructure and water infrastructure.
Capital expenditures for drilling and development totaled $1,385 million and $783 million during 2017 and 2016, respectively. The Company spud 201 gross wells in 2017, including 144 horizontal Marcellus wells, 49 horizontal Upper Devonian wells, seven horizontal Ohio Utica wells and one other well. The Company spud 135 gross wells in 2016, including 117 horizontal Marcellus wells, 13 horizontal Upper Devonian wells and 4 horizontal Utica wells. The increase in capital expenditures for well development in 2017 was driven primarily by the timing of drilling and completions activities between years and an increase in
wells spud. Capital expenditures for 2017 also included $1,007 million for property acquisitions, compared to $1,284 million of capital expenditures in 2016 for property acquisitions. These acquisitions are discussed in Note 10 to the Consolidated Financial Statements.
Capital expenditures for drilling and development totaled $783 million and $1,670 million during 2016 and 2015, respectively. The Company spud 161 gross wells in 2015, including 133 horizontal Marcellus wells, 24 horizontal Upper Devonian wells and 4 other wells, including 2 Utica wells. The decrease in capital expenditures for well development in 2016 was driven primarily by the timing of drilling and completions activities between years, a decrease in wells spud, lower costs per well and operational efficiencies. Capital expenditures for 2016 also included $1,284 million for property acquisitions, compared to $182 million of capital expenditures in 2015 for property acquisitions. The Company executed multiple large transactions during 2016 that resulted in the Company's acquisition of approximately 122,100 net Marcellus acres located primarily in northern West Virginia and southwestern Pennsylvania discussed in Note 10 to the Consolidated Financial Statements.
Capital expenditures for the EQM gathering and transmission operations totaled $308 million for 2017 and $587 million for 2016, primarily related to expansion capital expenditures. Expansion capital expenditures are expenditures incurred for capital improvements that EQM expects to increase its operating income or operating capacity over the long term. This decrease in expansion capital expenditures primarily related to OVC, which was placed into service in the fourth quarter of 2016.
Capital expenditures for the gathering, transmission and storage operations totaled $430 million for 2015, primarily related to expansion capital expenditures.
Financing Activities
Cash flowsNet cash provided by financing activities totaled $1,533.1was $32 million for 2017 as2020 compared to $1,399.5net cash used in financing activities of $249 million for 2016. During 2017,2019. For 2020, the Company's primary sourcessource of financing cash flows werewas net proceeds from the 2017 Notes Offering (defined in Note 15 toissuance of debt and equity and the Consolidated Financial Statements) and borrowings on credit facilities. The primary financing uses of cash during 2017 were redemptions and repayment of Rice's Senior Notes and credit facilities in connection with the closing of the Rice Merger, redemption of the Company's Senior Notes and distributions to noncontrolling interests.
On January 17, 2018, the Board of Directors of the Company declared a regular quarterly cash dividend of three cents per share, payable March 1, 2018, to the Company’s shareholders of record at the close of business on February 14, 2018.
On January 18, 2018, the Board of Directors of EQGP's general partner declared a cash distribution to EQGP's unitholders for the fourth quarter of 2017 of $0.244 per common unit, or approximately $64.9 million. The cash distribution will be paid on February 23, 2018 to unitholders of record, including the Company, at the close of business on February 2, 2018.
On January 18, 2018, the Board of Directors of EQM’s general partner declared a cash distribution to EQM’s unitholders for the fourth quarter of 2017 of $1.025 per common unit. The cash distribution was paid on February 14, 2018 to unitholders of record, including EQGP, at the close of business on February 2, 2018. Cash distributions by EQM to EQGP were approximately $65.7 million consisting of: $22.4 million in respect of its limited partner interest, $2.2 million in respect of its general partner interest and $41.1 million in respect of its IDRs in EQM.
On January 18, 2018, the Board of Directors of RMP’s general partner declared a cash distribution to RMP’s unitholders for the fourth quarter of 2017 of $0.2917 per common and subordinated unit. The cash distribution was paid on February 14, 2018 to unitholders of record, including Rice Midstream GP Holdings, LP (RMGP), which is an indirect wholly owned subsidiary of EQT, at the close of business on February 2, 2018. Cash distributions by RMP to RMGP were approximately $11.4 million, consisting of $8.4 million in respect of its limited partner interest and $3 million in respect of its IDRs in RMP.
Cash flows provided by financing activities totaled $1,399.5 million for 2016 as compared to $1,832.5 million for 2015. During 2016, the Company's primary sourcesuse of financing cash flows werewas net proceeds from its public offeringsrepayments of common stock and from EQM's public offerings of common units under EQM’s $750 million at-the-market (ATM) common unit offering program (the EQM $750 Million ATM Program), as well as proceeds received from the issuance of EQM Senior Notes. The primary financing uses of cash during 2016 were net credit facility repayments under the EQM credit facility, distributions to noncontrolling interests, taxes related to the vesting or exercise of equity awards and dividends. In 2015, the Company’s primary sources of financing cash flows were the issuance of EQM and EQGP common units and net borrowings on EQM’s credit facility whiledebt. For 2019, the primary uses of financing cash flows were net repayments of Senior Notesdebt and distributions to noncontrolling interests.
The Company may from time to time seek to repurchase its outstanding debt securities. Such repurchases, if any, will depend on prevailing market conditions, the Company's liquidity requirements, contractual and legal restrictions and other factors.
Revolving Credit Facilities
EQT primarily utilizescredit facility borrowings, under its revolving credit facilities to fund capital expenditures in excess of cash flow from operating activities until the expenditures can be permanently financed and to fund required margin deposits on derivative commodity instruments. Margin deposit requirements vary based on natural gas commodity prices, the Company's credit ratings and the amount and typeprimary source of derivative commodity instruments. Duringfinancing cash flows was net proceeds from borrowings on the year ended December 31, 2017, the Company also borrowed under the Company's $2.5 billion revolving credit facility to fund a portion of the cash Merger Consideration and pay expenses related to the Rice Merger. In addition, upon the closing of the Rice Merger on November 13, 2017, certain existing letters of credit issued for the account of Rice and its subsidiaries were transferred to the Company's $2.5 billion credit facility.
Term Loan Facility. See Note 1410 to the Consolidated Financial Statements for further discussion of EQT's, EQM'sour debt.
On March 26, 2020, we announced the suspension of our quarterly cash dividend on our common stock for purposes of accelerating cash flow to be used for our Deleveraging Plan.
Depending on our actual and RMP's credit facilities. anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may from time to time seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or privately negotiated transactions. The amounts involved in any such transactions may be material. Additionally, we plan to dispose of our remaining retained shares of Equitrans Midstream's common stock and use the proceeds to reduce our debt.
See alsoItem 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2019, which is incorporated herein by reference, for discussion and analysis of operating, investing and financing activities for the revolving loan agreement between EQT and EQM in Note 4 to the Consolidated Financial Statements.year ended December 31, 2018.
Security RatingsandFinancing Triggers
The table below reflects the credit ratings forand rating outlooks assigned to our debt instruments of the Company at December 31, 2017. Changes inFebruary 12, 2021. Our credit ratings may affect the Company’s cost of short-term debt through interest rates and fees under its lines of credit. These ratings may also affect collateral requirements under derivative instruments, pipeline capacity contracts, joint venture arrangements and subsidiary construction contracts, rates available on new long-term debt and access to the credit markets.
|
| | | | |
Rating Service | | Senior
Notes
| | Outlook |
Moody’s Investors Service (Moody's) | | Baa3 | | Stable |
Standard & Poor’s Ratings Service (S&P) | | BBB | | Negative |
Fitch Ratings Service (Fitch) | | BBB- | | Stable |
The table below reflects the credit ratings for debt instruments of EQM at December 31, 2017. Changes in credit ratings may affect EQM’s cost of short-term debt through interest rates and fees under its lines of credit. These ratings may also affect collateral requirements under joint venture arrangements and subsidiary construction contracts, rates available on new long-term debt and access to the credit markets.
|
| | | | |
Rating Service | | Senior
Notes
| | Outlook |
Moody's | | Ba1 | | Stable |
S&P | | BBB- | | Stable |
Fitch | | BBB- | | Stable |
RMP has no long-term debt and is not currently rated by Moody’s, S&P, or Fitch.
The Company’s and EQM’s credit ratingsrating outlooks are subject to revision or withdrawal at any time by the assigning rating organization,agency, and each rating should be evaluated independently ofindependent from any other rating. The Company and EQMWe cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a credit rating agency if, in itsthe rating agency's judgment, circumstances so warrant. If anySee Note 3 to the Consolidated Financial Statements for further discussion of what is deemed investment grade.
| | | | | | | | | | | | | | |
| Rating agency | | Senior notes | | Outlook |
| Moody's Investors Service (Moody's) | | Ba2 | | Stable |
| Standard & Poor's Ratings Service (S&P) | | BB | | Stable |
| Fitch Ratings Service (Fitch) | | BB | | Positive |
Changes in credit rating agency downgrades the ratings particularly below investment grade, the Company’s or EQM’smay affect our access to the capital markets, may be limited, borrowing coststhe cost of short-term debt through interest rates and margin depositsfees under our lines of credit, the interest rate on the Company’s derivative contracts would increase, counterparties may request additional assurances, including collateral, andAdjustable Rate Notes, the potentialrates available on new long-term debt, our pool of investors and funding sources, may decrease. The requiredthe borrowing costs and margin deposit requirements on the Company’sour OTC derivative instruments isand credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. Margin deposits on our OTC derivative instruments are also subject to significant change as a result of factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and hedging counterparties. As of February 12, 2021, we had sufficient unused borrowing capacity, net of letters of credit, under our credit facility to satisfy any requests for margin deposit or other collateral that our counterparties are permitted to request of us pursuant to our OTC derivative instruments, midstream services contracts and other contracts. As of February 12, 2021, such assurances could be up to approximately $1.0 billion, inclusive of letters of credit, OTC derivative instrument margin deposits and other collateral posted of approximately $0.9 billion in the hedging counterpartiesaggregate. See Notes 3 and the Company. Investment grade refers10 to the quality of a company's credit as assessed by one or more credit rating agencies. In order to be considered investment grade, a company must be rated BBB- or higher by S&P, Baa3 or higher by Moody's, and BBB- or higher by Fitch. Anything below these ratings is considered non-investment grade.Consolidated Financial Statements for further information.
The Company’sOur debt agreements and other financial obligations contain various provisions that, if not complied with, could result in terminationdefault or event of the agreements, require early paymentdefault under our credit facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under the debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. The Company’sOur credit facility contains financial covenants that require us to have a
total debt-to-total capitalization ratio no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income (OCI).income. As of December 31, 2017, the Company was2020, we were in compliance with all debt provisions and covenants.
EQM’s debt agreements and other financial obligations contain various provisions that, if not complied with, could result in terminationSee Note 10 to the Consolidated Financial Statements for a discussion of the agreements, require early payment of amounts outstanding or similar actions. The most significant covenants and events of defaultborrowings under the debt agreements relate to maintenance of a permitted leverage ratio, limitations on transactions with affiliates, limitations on restricted payments, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of and certain other defaults under other financial obligations and change of control provisions. Under EQM's $1 billionour credit facility, EQM is required to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (or not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions). As of December 31, 2017, EQM was in compliance with all debt provisions and covenants.facility.
The RMP credit facility contains various provisions that, if not complied with, could result in termination of the agreement, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the RMP credit facility relate to maintenance of certain financial ratios, as described below, limitations on certain investments and acquisitions, limitations on transactions with affiliates, limitations on restricted payments, limitations on the incurrence of additional indebtedness, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of and certain other defaults under other financial obligations and change of control provisions. The RMP credit facility requires RMP to maintain the following financial ratios:
•an interest coverage ratio of at least 2.50 to 1.0;
•a consolidated total leverage ratio of not more than 4.75 to 1.0, and after electing to issue senior unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.0 (with certain increases for measurement periods following the completion of certain acquisitions); and
•if RMP elects to issue senior unsecured notes, a consolidated senior secured leverage ratio of not more than 3.50 to 1.0.
As of December 31, 2017, RMP and RMP OpCo were in compliance with all credit facility provisions and covenants.
EQM ATM Program
During 2015, EQM entered into an equity distribution agreement that established the EQM $750 million ATM Program. EQM had approximately $443 million in remaining capacity under the program as of February 15, 2018.
RMP ATM Program
During 2016, RMP entered into an equity distribution agreement that established the RMP $100 million ATM equity distribution program. RMP had approximately $83.7 million in remaining capacity under the program as of February 15, 2018.
Commodity Risk Management
The substantial majority of the Company’sour commodity risk management program is related to hedging sales of the Company’sour produced natural gas. The Company’s overall objective in thisof our hedging program is to protect cash flowflows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments currently utilized by the Companythat we use are primarily NYMEX swaps, collarsswap, collar and options.option agreements. The
As of January 31, 2018,following table summarizes the approximate volumes and prices of the Company’s derivative commodity instruments hedging salesour NYMEX hedge positions through 2024 as of produced gas for 2018 through 2020 were:February 12, 2021.
|
| | | | | | | | | | | | |
| | | 2018 (a)(b)(c) | | 2019 (b) | | 2020 |
| NYMEX Swaps | | |
| | |
| | |
|
| Total Volume (Bcf) | | 541 |
| | 234 |
| | 234 |
|
| Average Price per Mcf (NYMEX) (d) | | $ | 3.14 |
| | $ | 3.03 |
| | $ | 3.05 |
|
| Collars | | | | | | |
| Total Volume (Bcf) | | 117 |
| | 66 |
| | — |
|
| Average Floor Price per Mcf (NYMEX) (d) | | $ | 3.28 |
| | $ | 3.15 |
| | $ | — |
|
| Average Cap Price per Mcf (NYMEX) (d) | | $ | 3.78 |
| | $ | 3.68 |
| | $ | — |
|
| Puts (Long) | | | | | | |
| Total Volume (Bcf) | | 10 |
| | 7 |
| | — |
|
| Average Floor Price per Mcf (NYMEX)* | | $ | 2.91 |
| | $ | 2.94 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 (a) | | 2022 | | 2023 | | 2024 | | |
| Swaps: | | | | | | | | | |
| Volume (MMDth) | 1,082 | | | 455 | | | 69 | | | 2 | | | |
| Average Price ($/Dth) | $ | 2.71 | | | $ | 2.66 | | | $ | 2.48 | | | $ | 2.67 | | | |
| Calls – Net Short: | | | | | | | | | |
| Volume (MMDth) | 407 | | | 284 | | | 77 | | | 15 | | | |
| Average Short Strike Price ($/Dth) | $ | 2.91 | | | $ | 2.89 | | | $ | 2.89 | | | $ | 3.11 | | | |
| Puts – Net Long: | | | | | | | | | |
| Volume (MMDth) | 227 | | | 135 | | | 69 | | | 15 | | | |
| Average Long Strike Price ($/Dth) | $ | 2.59 | | | $ | 2.35 | | | $ | 2.40 | | | $ | 2.45 | | | |
| Fixed Price Sales (b): | | | | | | | | | |
| Volume (MMDth) | 72 | | | 4 | | | 3 | | | — | | | |
| Average Price ($/Dth) | $ | 2.50 | | | $ | 2.38 | | | $ | 2.38 | | | $ | — | | | |
(a)Full year 20182021.
| |
(b) | The Company also sold calendar year 2018 and 2019 calls for approximately 64 Bcf and 45 Bcf, respectively, at strike prices of $3.49 per Mcf and $3.69 per Mcf, respectively. |
(c) For 2018,(b)The difference between the Company also sold puts for approximately 3 Bcf at a strikefixed price of $2.63 per Mcf.
| |
(d) | and NYMEX price is included in average differential presented in our price reconciliation in the "Average Realized Price Reconciliation." The average price is based on a conversion rate of 1.05 MMBtu/Mcf. |
The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. The difference between these sales pricescan be physically or financially settled.
For 2021, 2022, 2023 and NYMEX are included in average differential on the Company's price reconciliation under "Consolidated Operational Data". The Company has fixed price physical sales for 2018 and 2019 of 121 Bcf and 37 Bcf, respectively, at average NYMEX prices of $2.93 per Mcf and $3.04 per Mcf, respectively. For 2018, the Company has a2024, we have natural gas sales agreementagreements for approximately 35 Bcf per year18 MMDth, 18 MMDth, 88 MMDth and 11 MMDth, respectively, that includes ainclude average NYMEX ceiling priceprices of $4.88 per Mcf. For 2018, 2019$3.17, $3.17, $2.84 and 2020, the Company has a natural gas sales agreement for approximately 49 Bcf per year that includes a NYMEX ceiling price of $3.36 per Mcf. For 2018, 2019 and 2020, the Company also has a natural gas sales agreement for approximately 7 Bcf per year that includes a NYMEX floor price of $2.16 per Mcf and a NYMEX ceiling price of $4.47 per Mcf. Currently, the Company has$3.21, respectively. We have also entered into derivative instruments to hedge basis and a limited number of contracts to hedge its NGLs exposure. The Companybasis. We may also use other contractual agreements in implementing itsto implement our commodity hedging strategy.strategy from time to time.
During 2020, we purchased $47 million of net options with the primary purpose of reducing future NYMEX based payments that could be due in 2021, 2022 and 2023 to Equitrans Midstream related to the Henry Hub Cash Bonus (defined and discussed in Note 5 to the Consolidated Financial Statements) provided for by the Consolidated GGA.
See Item 7A, “Quantitative7A., "Quantitative and Qualitative Disclosures About Market Risk,”Risk" and Note 73 to the Consolidated Financial Statements for further discussion of the Company’sour hedging program.
Other Items
Off-Balance Sheet Arrangements
In connection with the sale of its NORESCO domestic operations in December 2005, the Company agreed to maintain in place guarantees of certain warranty obligations of NORESCO. The savings guarantees provided that once the energy-efficiency construction was completed by NORESCO, the customer would experience a certain dollar amount of energy savings over a period of years. The undiscounted maximum aggregate payments that may be due related to these guarantees were approximately $95 million as of December 31, 2017, extending at a decreasing amount for approximately 11 years.
As of December 31, 2017, EQM had issued a $91 million performance guarantee in favor of the MVP Joint Venture to provide performance assurances for MVP Holdco's obligations to fund its proportionate share of the construction budget for the MVP.
The NORESCO guarantees and the MVP Guarantee are exempt from ASC Topic 460, Guarantees. The Company has determined that the likelihood it will be required to perform on these arrangements is remote and any potential payments are expected to be immaterial to the Company’s financial position, results of operations and liquidity. As such, the Company has not recorded any liabilities in its Consolidated Balance Sheets related to these guarantees.
Rate Regulation
As described under “Regulation” in Item 1, “Business,” the Company’s transmission and storage operations and a portion of its gathering operations are subject to various forms of rate regulation. As described inSee Note 117 to the Consolidated Financial Statements regulatory accounting allows the Company to defer expenses and income as regulatory assets and liabilities which reflect future collections or payments through the regulatory process. The Company believes that it will continue to be subject to rate regulation that will provide for the recoverya discussion of the deferred costs. See “Our need to comply with comprehensive, complex and sometimes unpredictable government regulations may increase our costs and limit our revenue growth, which may result in reduced earnings.” in Item 1A, “Risk Factors” for potential risks related to the regulation of rates by the FERC.guarantees.
Schedule of Contractual Obligations
The table below presents the Company’s long-term contractual obligations as of December 31, 2017 in total and by periods. Purchase obligations exclude the Company’s contractual obligations relating to its binding precedent agreements and other natural gas transmission and gathering capacity agreements with EQM, for which future payments related to such agreements totaled $5.6 billion as of December 31, 2017. These capacity commitments have terms extending up to 20 years. Purchase obligations also exclude future capital contributions to the MVP Joint Venture and purchase obligations of the MVP Joint Venture.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Total | | 2018 | | 2019-2020 | | 2021-2022 | | 2023+ |
| | | (Thousands) |
| Purchase obligations (a) | | $ | 16,616,818 |
| | $ | 824,813 |
| | $ | 2,045,143 |
| | $ | 2,004,729 |
| | $ | 11,742,133 |
|
| Senior Notes | | 5,618,200 |
| | 8,000 |
| | 1,711,200 |
| | 1,524,000 |
| | 2,375,000 |
|
| Interest payments on Senior Notes (b) | | 1,515,749 |
| | 241,748 |
| | 449,128 |
| | 333,269 |
| | 491,604 |
|
| Credit facility borrowings (c) | | 1,761,000 |
| | — |
| | 286,000 |
| | 1,475,000 |
| | — |
|
| Operating leases (d) | | 231,515 |
| | 70,887 |
| | 64,779 |
| | 27,185 |
| | 68,664 |
|
| Water infrastructure (e) | | 19,547 |
| | — |
| | — |
| | — |
| | 19,547 |
|
| Other liabilities (f) | | 78,748 |
| | 30,949 |
| | 47,799 |
| | — |
| | — |
|
| Total contractual obligations | | $ | 25,841,577 |
| | $ | 1,176,397 |
| | $ | 4,604,049 |
| | $ | 5,364,183 |
| | $ | 14,696,948 |
|
| |
(a) | Purchase obligations are primarily commitments for demand charges under existing long-term contracts and binding precedent agreements with various unconsolidated pipelines, including commitments from the Company to the MVP Joint Venture, some of which extend up to 20 years or longer. The Company has entered into agreements to release some of its capacity to various third parties. Purchase obligations also include commitments with third parties for processing capacity in order to extract heavier liquid hydrocarbons from the natural gas stream. |
| |
(b) | Interest payments exclude interest related to the credit facility borrowings and the Floating Rate Notes (defined in Note 15 to the Consolidated Financial Statements) as the interest rates on the Company's, EQM's and RMP's credit facilities and the Floating Rate Notes are variable. |
| |
(c) | Credit facility borrowings were classified based on the termination dates of the Company's, EQM's and RMP's credit facilities. |
| |
(d) | Operating leases are primarily entered into for various office locations and warehouse buildings, as well as dedicated drilling rigs in support of the Company’s drilling program. The obligations for the Company’s various office locations and warehouse buildings totaled approximately $139.2 million as of December 31, 2017. The Company has agreements with several drillers to provide drilling equipment and services to the Company over the next four years. These obligations totaled approximately $92.3 million as of December 31, 2017. As of December 31, 2017, the Company had eight horizontal drilling rigs under contract, and an additional horizontal rig will become active on April 1, 2018. All of these will expire in 2019 with dates in this order: June 30, July 31, August 31 (2), September 30, October 31, November 30 and December 31 (2). The Company also had seven tophole drilling rigs under contract, six of which expire in 2018 and one that expires in 2019. Of the six tophole rigs that expire in 2018, the dates are in this order: January 3, February 3, February 25, June 2, August 27 and December 22. The expiration date for the tophole rig in 2019 is March 29. These drilling obligations have been included in the table above. The values in the table represent the gross amounts that the Company is committed to pay as operator. However, the Company will record in the Consolidated Financial Statements the Company's proportionate share of the amounts shown based on its working interest. |
(e) See Note 20 for additional information.
| |
(f) | The other liabilities line represents commitments for total estimated payouts for the 2017 EQT Value Driver Award Program, 2017 Incentive PSU Program, 2017 restricted stock unit liability awards, 2016 EQT Value Driver Award Program and 2016 restricted stock unit liability awards. See “Critical Accounting Policies and Estimates” below and Note 18 to the Consolidated Financial Statements for further discussion regarding factors that affect the ultimate amount of the payout of these obligations. |
As discussed in Note 11 to the Consolidated Financial Statements, the Company had a total reserve for unrecognized tax benefits at December 31, 2017 of $301.6 million, of which $84.1 million is offset against deferred tax assets since it would primarily reduce the alternative minimum tax credit carryforwards. The Company is currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities; therefore, this amount has been excluded from the schedule of contractual obligations.
Commitments and Contingencies
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company.us. While the amounts claimed may be substantial, the Company iswe are unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accruesWe accrue legal and other direct costs related to loss contingencies when actually incurred. The Company hasWe have established reserves it believesthat we believe to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believeswe believe that the ultimate outcome of any matter currently pending against the Companyus will not materially affect the Company’sour financial position,condition, results of operations or liquidity.
See Note 2016 to the Consolidated Financial Statements for furthera discussion of the Company’sour commitments and contingencies. See also the discussion of the revolving loan agreement between EQT and EQM in Note 4 to the Consolidated Financial Statements.Item 3., "Legal Proceedings."
Recently Issued Accounting Standards
The Company'sOur recently issued accounting standards are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.Statements.
Critical Accounting Policies and Estimates
The Company’sOur significant accounting policies are described in Note 1 to the Consolidated Financial Statements. TheManagement's discussion and analysis of the Consolidated Financial Statements and results of operations are based upon the Company’son our Consolidated Financial Statements, which have been prepared in accordance with United States GAAP. The preparation of the Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and
expenses and the related disclosure of contingent assets and liabilities. The following critical accounting policies, which were reviewed by the Company’s Audit Committee of our Board of Directors (the Audit Committee), relate to the Company’sour more significant judgments and estimates used in the preparation of itsour Consolidated Financial Statements. Actual results could differ from thoseour estimates.
Accounting for Gas, NGL and Oil and Gas Producing Activities: The Company usesActivities. We use the successful efforts method of accounting for itsour oil and gas producing activities.
The carrying values of the Company’sour proved oil and gas properties are reviewed for impairment generally on a field-by-field basis when events or circumstances indicate that the remaining carrying value may not be recoverable. TheTo determine whether impairment of our oil and gas properties has occurred, we compare the estimated expected undiscounted future cash flows used to testthe carrying values of those properties for recoverabilityproperties. Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted probable reserves utilizingand assumptions generally consistent with the assumptions utilizedused by the Company's managementus for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil adjusted accordingly for basis differentials, future operating costs and inflation, some of which are interdependent.inflation. Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their estimates of fair value.value estimates.
Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis.basis at least annually. Indicators of potential impairment include changes in development plans resulting fromdue to economic factors, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. If it is determined thatwe do not intend to drill on the properties will not yield proved reservesproperty prior to their expirations,expiration of the related costs are expensed inlease or do not have the period in which that determinationintent and ability to extend, renew, trade or sell the lease prior to expiration, impairment expense is made. recorded.
The Company believes that the accounting estimate related to theWe believe accounting for oilgas, NGL and gasoil producing activities is a “critical"critical accounting estimate” asestimate" because the evaluations of impairment of proved properties involve significant judgment about future events, such as future sales prices of natural gas and NGLs and future production costs, estimates ofas well as the amount of natural gas and NGLs recorded and the timing of those recoveries. Significant changes in these estimates could result in the costs of our proved and unproved properties not being recoverable; therefore, we would be required to recognize impairment. See "Impairment of Oil and Gas Properties and Goodwill" aboveProperties" and Note 1 to the Consolidated Financial Statements for additional information regarding the Company’son our impairments of proved and unproved oil and gas properties.
Oil and Gas Reserves: Reserves. Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and gas which,that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.
The Company’sOur estimates of proved reserves are made and reassessed annually using geological, and reservoir data as well asand production performance data. Reserve estimates are prepared and updated by the Company’sour engineers and audited by the Company’s independent engineers. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in somecertain proved reserves due to reaching economic limits sooner. A material change in the estimated volumes of reserves could have an impact on the depletion rate calculation and the Company's financial statements.our Consolidated Financial Statements.
The Company estimatesWe estimate future net cash flows from natural gas, NGLs and crude oil reserves based on selling prices and costs using a 12-monthtwelve-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-monthtwelve-month period whichand, as such, is subject to change in subsequent periods. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense is computed usingbased on future statutory tax rates and giving effect to tax deductions and credits available under current laws and which relate to oil and gas producing activities.laws.
The Company believes that the accounting estimate related toWe believe oil and gas reserves is a “critical"critical accounting estimate”estimate" because the Companywe must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the estimated timing of development expenditures. Future results of operations and the strength of the balance sheetour Consolidated Balance Sheet for any particular quarterly or annual period could be materially affected by changes in the Company’sour assumptions. Significant changes in these estimates could result in a change to our estimated reserves, which could lead to a material change to our production depletion expense. See "Impairment of Oil and Gas Properties and Goodwill" aboveProperties" for additional information regarding the Company’son our oil and gas reserves.
Income Taxes: The Company recognizesTaxes. We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the Company’sour Consolidated Financial Statements or tax returns.
The Company hasWe have recorded deferred tax assets principally resulting from federal and state NOL carryforwards, an alternative minimum taxAMT credit carryforward, other federal tax credit carryforwards, unrealized capacity contract losses, incentive compensation and investmentinvestments in partnerships. The Company hassecurities. We have established a valuation allowance against a portion of the deferred tax assets related primarily to the federal and state NOL carryforwards and alternative minimum tax credit carryforward, as it is believed thatour investment in Equitrans Midstream because we believe it is more likely than not that certainthose deferred tax assets will not all be fully realized. We established a valuation allowance against the state and part of the federal deferred tax asset related to our investment in Equitrans Midstream because the fair value loss is not expected to be fully realized for tax purposes due to capital loss limitations. No other significant valuation allowances have been established as it is believedwe believe that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize thesethe deferred tax assets. Any determinationChanges to change theour valuation allowance would impact the Company’sour income tax expense and net income in the period in which such a determination is made.
The Company also estimatesWe estimate the amount of financial statement benefit to recordrecorded for uncertain tax positions as described inpositions. See Note 119 to the Company’sour Consolidated Financial Statements.
The Company believes that accounting estimates related toWe believe income taxes are “critical"critical accounting estimates”estimates" because the Companywe must assess the likelihood that our deferred tax assets will be recovered from future taxable income and exercise judgment regardingon the amount of financial statement benefit to recordrecorded for uncertain tax positions. When evaluating whether or not a valuation allowance mustshould be established, on deferred tax assets, the Company exerciseswe exercise judgment in determiningon whether it is more likely than not (a likelihood of more than 50%) that somea portion or all of the deferred tax assets will not be realized. The Company considersTo determine whether a valuation allowance is needed, we consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed, including carrybacks, tax planning strategies, reversalreversals of deferred tax assets and liabilities and forecasted future taxable income. In makingTo determine the determination related toamount of financial statement benefit recorded for uncertain tax positions, the Company considerswe consider the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit.date. To the extent that ana valuation allowance or uncertain tax position or valuation allowance is established or increased or decreased during a period, the Company must includewe record an expense or benefit withinin income tax expense in the income statement.our Statements of Consolidated Operations. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’sour assumptions. A change to future taxable income or tax planning strategies could impact our ability to utilize deferred tax assets, which would increase or decrease our income tax expense and taxes paid.
Derivative Instruments: The Company entersInstruments. We enter into derivative commodity instrument contracts primarily to mitigatereduce exposure to commodity price risk associated with future sales of natural gas production. The Company also enters into derivative instruments to hedge basis and to hedge exposure to fluctuations in interest rates.
The Company estimatesWe estimate the fair value of all derivativeour financial instruments using quoted market prices wherewhen available. If quoted market prices are not available, the fair value is based uponon models that use market-based parameters, as inputs, including forward curves, discount rates, volatilities and nonperformance risk.risk, as inputs. Nonperformance risk considers the effect of the Company’sour credit standing on the fair value of liabilities and the effect of the counterparty’scounterparty's credit standing on the fair value of assets. The Company estimatesWe estimate nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to our credit rating or the Company’s or counterparty’scounterparty's credit rating and the yield ofon a risk-free instrument, and
credit default swap rates where available.instrument. The values reported in the financial statementsConsolidated Financial Statements change as these estimates are revised to reflect actual results or as market conditions or other factors, change, many of which are beyond the Company’s control.our control, change.
The Company believes that the accounting estimates related toWe believe derivative instruments are “critical"critical accounting estimates”estimates" because the Company’sour financial condition and results of operations can be significantly impacted by changes in the market value of the Company’sour derivative instruments due to the volatility of both NYMEX natural gas prices both NYMEX and basis. Future results of operations for any particular quarterly or annual period could be materially affected by changes in our assumptions. Refer to Item 7A., "Quantitative and Qualitative Disclosures about Market Risk" for discussion of a hypothetical increase or decrease of 10% in the Company’s assumptions.market price of natural gas.
Contingencies and Asset Retirement Obligations: The Company isObligations. We are involved in various regulatorylegal and legalregulatory proceedings that arise in the ordinary course of business. The Company recordsWe record a liability for contingencies based upon itson our assessment that a loss is probable and the amount of the loss can be reasonably estimated. The Company considersWe consider many factors in making these assessments, including historyhistorical experience and specifics of each matter.matter specifics. Estimates are developed in consultation with legal counsel and are based uponon an analysis of potential results.
We accrue a liability for asset retirement obligations based on an estimate of the amount and timing and amount of their settlement. For oil and gas wells, the fair value of the Company’sour plugging and abandonment obligations is required to be recorded at the time the obligations areobligation is incurred, which is typically at the time the wells arewell is spud. The Company operates and maintains its gathering systems and transmission and storage system and it intends to do so as long as supply and demand for natural gas exists, which the Company expects for the foreseeable future. The Company is under no legal or contractual obligation to restore or dismantle its gathering systems and transmission and storage system upon abandonment. Therefore, the Company does not have any asset retirement obligations related to its gathering systems and transmission and storage system as of December 31, 2017 and 2016.
The Company believes that the accounting estimates related toWe believe contingencies and asset retirement obligations are “critical"critical accounting estimates”estimates" because the Companywe must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligations.obligation settlement. In addition, the Companywe must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes in our assumptions. If we incur losses related to contingencies that are higher than we expect, we could incur additional costs to settle such obligations. If the Company’s assumptions.
Share-Based Compensation: The Company awards share-based compensation in connection with specific programs established under the 2009expected amount and 2014 Long-Term Incentive Plans. Awards to employees are typically made in the formtiming of performance-based awards, time-based restricted stock, time-based restricted units and stock options. Awards to directors are typically made in the form of phantom units that vest upon grant.
Restricted units and performance-based awards expected toour asset retirement obligations change, we will be satisfied in cash are treated as liability awards. For liability awards, the Company is required to estimate, onadjust the grant datecarrying value of our liabilities in future periods.
Contract Asset. In the first quarter of 2020, we entered into two share purchase agreements with Equitrans Midstream to sell to Equitrans Midstream 50% of our ownership of Equitrans Midstream's common stock in exchange for a combination of cash and on each reporting date thereafter until vestingrate relief under certain of our gathering agreements with EQM, an affiliate of Equitrans Midstream. The rate relief was effected through the execution the Consolidated GGA (defined and payment,discussed in Note 5to the Consolidated Financial Statements). We recorded a contract asset representing the estimated fair value of the ultimate payout based uponrate relief provided by the expected performance through, and value of the Company’s common stock on, the vesting date. The Company then recognizes a proportionate amount of the expense for each period in the Company’s financial statements over the vesting period of the award. The Company reviews itsConsolidated GGA. Key assumptions regarding performance and common stock value on a quarterly basis and adjusts its accrual when changes in these assumptions result in a material changeused in the fair value calculation included an estimated production volume forecast, a market-based discount rate and a probability-weighted estimate of the ultimate payouts.
Performance-based awards expected to be satisfied in Company common stock are treated as equity awards. For equity awards, the Company is required to determine the grant date fair value of the awards, which is then recognized as expense in the Company’s financial statements over the vesting period of the award. Determination of the grant date fair value of the awards requires judgments and estimates regarding, among other things, the appropriate methodologies to follow in valuing the awards and the related inputs required by those valuation methodologies. Most often, the Company is required to obtain a valuation based upon assumptions regarding risk-free rates of return, dividend yields, expected volatilities and the expected term of the award. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the historical dividend yield of the Company’s common stock adjusted for any expected changes and, where applicable, of the common stock of the peer group members at the time of grant. Expected volatilities are based on historical volatility of the Company’s common stock and, where applicable, the common stock of the peer group members at the time of grant. The expected term represents the period of time elapsing during the applicable performance period.
For time-based restricted stock awards, the grant date fair value of the awards is recognized as expense in the Company’s financial statements over the vesting period, historically three years. For director phantom units (which vest on the date of grant) expected to be satisfied in equity, the grant date fair value of the awards is recognized as an expense in the Company’s financial statements in the year of grant. The grant date fair value, in both cases, is determined based upon the closing price of the Company’s common stock on thein-service date of the grant.Mountain Valley Pipeline. Beginning with the Mountain Valley Pipeline in-service date, we will recognize amortization of the contract asset over a period of approximately four years in a manner consistent with the expected timing of our realization of the economic benefits of the rate relief provided by the Consolidated GGA.
For non-qualified stock options,We believe the grant date fair valueConsolidated GGA contract asset is recognized as expensea "critical accounting estimate" because the assumptions used in the Company’s financial statements over the vesting period, typically three years. The Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options, which includes assumptions for a risk-free interest rate, dividend yield, volatility factor and expected term. The risk-free rate for periods within the contractual lifevaluation of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the dividend yield of the Company’s common stock at the time of grant. The expected volatility is based on historical volatility of the Company’s common stock at the time of grant. The expected term represents the period of time that options granted are expected to be outstanding based on historical option exercise experience at the time of grant.
The Company believes that the accounting estimates related to share-based compensation are “critical accounting estimates” because they may change from period to period based on changes in assumptions about factors affecting the ultimate payout of awards, including the number of awards to ultimately vest and the market price and volatility of the Company’s common stock.contract asset involved significant judgment. Future results of operations for any particular quarterly or annual period could be materially affected by changes in our assumptions. A change in the Company’s assumptions. Seeestimated production volume forecast, the market-based discount rate or the probability-weighted estimate of the in-service date of the Mountain Valley Pipeline could have resulted in a change in the valuation of the contract asset.
Convertible Notes. In the second quarter of 2020, we issued the Convertible Notes (defined and discussed in Note 1810 to the Consolidated Financial StatementsStatements).
At issuance, we separated the Convertible Notes into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of similar debt instruments that do not have associated convertible features. The carrying amount of the equity component, representing the conversion option, was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes. The equity component is not remeasured as long as it continues to meet the condition for additional information regardingequity classification. The excess of the Company’s share-based compensation.principal amount of the liability component over its carrying amount (the debt discount) will be amortized to interest expense over the term of the Convertible Notes using the effective interest rate method. Issuance costs were allocated to the liability and equity components of the Convertible Notes based on their relative fair values.
In connection with the Convertible Notes offering, we entered into the Capped Call Transactions (defined and discussed in Note 10 to the Consolidated Financial Statements). The Capped Call Transactions are separate from the Convertible Notes. The Capped Call Transactions were recorded in shareholders' equity and were not accounted for as derivatives. The cost to purchase the Capped Call Transactions was recorded as a reduction to equity and will not be remeasured.
Upon conversion of the Convertible Notes, we intend to use a combined settlement approach to satisfy our settlement obligation by paying or delivering to holders of the Convertible Notes cash equal to the principal amount of the obligation and EQT common stock for amounts that exceed the principal amount of the obligation. As such, we used the treasury stock method for the diluted earnings per share (EPS) calculation, and there is no adjustment to the diluted EPS numerator for the cash-settled portion of the instrument.
We believe the accounting complexity of the Convertible Notes is a "critical accounting estimate" because we used judgment to determine the balance sheet classification, to determine the treatment of the Capped Call Transactions and to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.
Business Combinations:Combinations. Accounting for the acquisition of a business combination requires a company to record the identifiable assets and liabilities acquired to be recorded at fair value.
In the fourth quarter of 2020, we completed the Chevron Acquisition. The most significant assumptions used in a business combinationaccounting for the Chevron Acquisition include those used to estimate the fair value of the oil and gas properties acquired. Theacquired, the acquired investment in midstream gathering assets and acquired contract liabilities. We calculated the fair value of the acquired proved naturaloil and gas properties, is determinedincluding in-process wells, using a risk-adjusted after-tax discounted cash flow analysis that was based upon significant assumptions includingon the following key assumptions: future commodity prices;prices, projections of estimated quantities of reserves; projections ofreserves, estimated future rates of production;production, projected reserve recovery factors, timing and amount of future development and operating costs; projected reserve recovery factors;costs and a weighted average cost of capital.
The Company utilizes the guideline transaction method to estimate the fair value of unproved properties acquired in a business combination which requires the Company to use judgment in considering the value per undeveloped acre in recent comparable transactions to estimate the value of unproved properties.
The estimated fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations, is estimated using the cost approach, which incorporates assumptions about the replacement costs for similar assets, the relative age of assets and any potential economic or functional obsolescence.
The fair values of the intangible assets are estimated using the multi-period excess earnings model which estimates revenues and cash flows derived from the intangible asset and then deducts portions of the cash flow that can be attributed to supporting assets otherwise recognized. The Company’s intangible assets are comprised of customer relationships and non-compete agreements.
The Rice Merger resulted in share-based compensation modification accounting which is treated as an exchange of the original award for a new award with total compensation cost equal to the grant-date fair value of the original award plus the incremental value of the modification to the award. The calculation of the incremental value is based on the excess of We calculated the fair value of the new (modified) awardacquired unproved properties using the guideline transaction method that was based on current circumstances overthe following key assumptions: future development plans from a market participant perspective and value per undeveloped acre. We calculated the fair value of our investment in the original option measured immediately before its terms are modifiedmidstream gathering assets primarily using a discounted cash flow analysis that was based on current circumstances.
The Company believes that the accounting estimates related to business combinations are “critical accounting estimates” because the Company must, in determiningfollowing key assumptions: projected revenues, expenses and capital expenditures. We calculated the fair value of acquired contract liabilities using estimated future volumes and annual contract commitments calculated on a discounted basis that was based on the following key assumptions: estimated future volumes and market participant cost of debt.
We believe business combinations are "critical accounting estimates" because the valuation of acquired assets acquired, make assumptionsand liabilities involves significant judgment about future commodity prices; projections of estimated quantities of reserves; projections of future rates of production; projections regarding the timing and amount of future development and operating costs; and projections of reserve recovery factors, per acre values of undeveloped property, replacement cost of and future cash flows from midstream assets, cash flow from customer relationships and non-compete agreements and the pre and post modification value of stock based awards. Different assumptions may result in materially different values for these assets which would impact the Company’s financial position and future results of operations.
Goodwill: Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business.
Goodwill is evaluated for impairment at least annually, or whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Company may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. To the extent that such indicators exist, a two-step goodwill impairment test is completed. The first step compares the fair value of a reporting unit to its carrying value. If the carrying amount of a reporting unit exceeds its fair value,
the second step is required which compares the implied fair value of the goodwill of a reporting unit to its carrying value. If the carrying value of the goodwill of a reporting unit exceeds its implied fair value, the difference is recognized as an impairment charge. The Company uses a combination of an income and market approach to estimate the fair value of a reporting unit.
The Company believes that the accounting estimates related to goodwill are “critical accounting estimates” because the fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results as well as other assumptions such as movement in the Company's stock price, weighted-average cost of capital, terminal growth rates and industry multiples. The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate; however, different assumptions and estimates could materially impact the calculated fair value and the resulting determinations about goodwill impairment which could materially impact the Company’sevents. Future results of operations and financial position. Additionally, future estimates may differfor any quarterly or annual period could be materially from current estimates andaffected by changes in our assumptions.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk and Derivative Instruments
The Company’sInstruments. Our primary market risk exposure is the volatility of future prices for natural gas and NGLs. The market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Northeast region in recent years. Due to the volatility of commodity prices, the Company iswe are unable to predict future potential movements in the market prices for natural gas including Appalachian basis, and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on itsour operations. Prolonged low, and/or significant, or extended declines in, natural gas and NGLs prices could adversely affect, among other things, the Company’sour development plans, which would decrease the pace of development and the level of the Company’sour proved reserves. Such changesIncreases in natural gas and NGLs prices may be accompanied by, or similar impacts on third party shippers on the Company's midstream assets could also impact the Company’s revenues, earnings or liquidity and could result in, material non-cash impairmentsincreased well drilling costs, increased production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels. In addition, to the recorded valueextent we have hedged our production at prices below the current market price, we will not benefit fully from an increase in the price of the Company’s property, plant and equipment.natural gas.
The Company uses derivativesoverall objective of our hedging program is to reduceprotect cash flows from undue exposure to the effectrisk of changing commodity price volatility. The Company'sprices. Our use of derivatives is further described in Notes 1 and 7Note 3 to the Consolidated Financial Statements and under the caption “Commodity"Commodity Risk Management” in theManagement" under "Capital Resources and Liquidity" section ofin Item 7, “Management’s7., "Management's Discussion and Analysis of Financial Condition and Results of Operations.” The Company uses" Our OTC derivative commodity instruments that are placed primarily with financial institutions and the creditworthiness of thesethose institutions is regularly monitored. The CompanyWe primarily entersenter into derivative instruments to hedge forecasted sales of production. The CompanyWe also entersenter into derivative instruments to hedge basis and exposure to fluctuations in interest rates. The Company’sOur use of derivative instruments is implemented under a set of policies approved by the Company’sour Hedge and Financial Risk Committee and reviewed by the Audit Committee of the Company'sour Board of Directors.
For the derivative commodity instruments used to hedge the Company’sour forecasted sales of production, most of which are hedged at, for the most part, NYMEX natural gas prices, the Company setswe set policy limits relative to the expected production and sales levels whichthat are exposed to price risk. The Company hasWe have an insignificant amount of financial natural gas derivative commodity instruments for trading purposes.
The derivative commodity instruments currently utilized by the Companywe use are primarily fixed price swap, agreements, collar agreements and option agreements. These agreements which may require payments to, or receipt of payments from, counterparties based on the differential between two prices for the commodity. The CompanyWe use these agreements to hedge our NYMEX and basis exposure. We may also use other contractual agreements in implementing itswhen executing our commodity hedging strategy.
The Company monitors We monitor price and production levels on a continuous basis and makesmake adjustments to quantities hedged as warranted. The Company’s overall objective in its hedging program is to protect a portion of cash flows from undue exposure to the risk of changing commodity prices.
With respect to the derivative commodity instruments held by the Company, the Company hedged portions of expected sales of equity production and portions of its basis exposure covering approximately 2,148 Bcf of natural gas and 8,943 Mbbls of NGLs as of December 31, 2017, and 646 Bcf of natural gas and 1,095 Mbbls of NGLs as of December 31, 2016. In connection with the Rice Merger, the Company assumed all outstanding derivative commodity instruments held by Rice, which significantly increased the volume of hedges. See the “Commodity Risk Management” section in the “Capital Resources and Liquidity” section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for further discussion.
A hypothetical decrease of 10% in the market price of natural gas from theon December 31, 20172020 and 2016 levels2019 would have increasedincrease the fair value of theseour natural gas derivative commodity instruments by approximately $386.2$501 million and $179.0$389 million, respectively. A hypothetical increase of 10% in the market price of natural gas from theon December 31, 20172020 and 2016 levels2019 would have decreaseddecrease the fair value of theseour natural gas derivative commodity instruments by approximately $384.9$495 million and $181.8$395 million, respectively. The Company determinedFor purposes of this analysis, we applied the 10% change in the fair valuemarket price of thenatural gas on December 31, 2020 and 2019 to our natural gas derivative commodity instruments as of December 31, 2020 and 2019 to calculate the hypothetical change in fair value. The change in fair value was determined using a method similar to itsour normal determination ofprocess for determining derivative commodity instrument fair value as described in Note 14 to the Consolidated Financial Statements. The Company assumed a 10% change in the price
The above analysis of theour derivative commodity instruments held by the Company does not include the offsetting impact that the same hypothetical price movement may have on the Company’sour physical sales of natural gas. The portfolio of derivative commodity instruments held to hedge the Company’sour forecasted produced gas approximates a portion of the Company’sour expected physical sales of natural gas. Therefore,gas; therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held to hedge the Company’sour forecasted production associated with the hypothetical changes in commodity prices referenced
above should be offset by a favorable impact on the Company’sour physical sales of natural gas, assuming that the derivative commodity instruments are not closed out in advance of their expected term and the derivative commodity instruments continue to function effectively as hedges of the underlying risk.
If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.
Interest Rate Risk
Risk. Changes in market interest rates affect the amount of interest the Company, EQGP, EQM and RMPwe earn on cash, cash equivalents and short-term investments and the interest rates the Company, EQM and RMPwe pay on borrowings under their respective revolvingon our credit facilitiesfacility and, the Company's floating rate notes. Allprior to its full redemption on June 30, 2020, our Term Loan Facility. None of the Company’sinterest we pay on our senior notes fluctuates based on changes to market interest rates. A 1% increase in interest rates on our borrowings on our credit facility and EQM’s Senior Notes, other thanterm loan facility during the year ended December 31, 2020 would have increased 2020 annual interest expense by approximately $5 million. A 1% increase in interest rates on our borrowings under our credit facility, term loan facility and floating rate notes are fixed rateduring the year ended December 31, 2019 would have increased 2019 annual interest expense by approximately $14 million.
Interest rates on the Adjustable Rate Notes fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and thus doFitch. For a discussion of credit rating downgrade risk, see Item 1A., "Risk Factors – Our exploration and production operations have substantial capital requirements, and we may not expose the Companybe able to fluctuations in its results of operationsobtain needed capital or liquidity from changes in market interest rates.financing on satisfactory terms." Changes in interest rates do affect the fair value of the Company’s and EQM’sour fixed rate debt. See Notes 14 and 15Note 10 to the Consolidated Financial Statements for further discussion of the Company’s, EQM’s, and RMP's borrowings, as applicable,our debt and Note 84 to the Consolidated Financial Statements for a discussion of fair value measurements, including the fair value of long-termour debt.
Other Market Risks
The Company isRisks. We are exposed to credit loss in the event of nonperformance by counterparties to our derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company’sOur OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as thatthe financial industry as a whole. The Company utilizesWe use various processes and analyses to monitor and evaluate itsour credit risk exposures. These include closelyexposures, including monitoring current market conditions and counterparty credit fundamentals and credit default swap rates.fundamentals. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enterswe enter into transactions primarily with financial counterparties that are of investment grade, entersenter into netting agreements whenever possible and may obtain collateral or other security.
Approximately 63%47%, or $242.0$456 million, of the Company’sour OTC derivative contracts outstanding at December 31, 20172020 had a positive fair value. Approximately 11%75%, or $33.1$718 million, of the Company’sour OTC derivative contracts outstanding at December 31, 20162019 had a positive fair value. The increase in derivative contracts with a positive fair value primarily relates to decreased forward NYMEX prices as well as settlements of contracts during 2017 that had a negative fair value as of December 31, 2016.
As of December 31, 2017, the Company was2020, we were not in default under any derivative contracts and had no knowledge of default by any counterparty to itsour derivative contracts. The CompanyDuring the year ended December 31, 2020, we made no adjustments to the fair value of our derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company’sour established fair value procedure. The Company monitorsWe monitor market conditions that may impact the fair value of our derivative contracts reported in the Consolidated Balance Sheets.contracts.
The Company is alsoWe are exposed to the risk of nonperformance by credit customers on physical sales or transportation of natural gas. A significant amount of revenuesgas, NGLs and oil. Revenues and related accounts receivable from our operations are generated primarily from the sale of produced natural gas, NGLs and NGLsoil to certain marketers, utilityutilities and industrial customers located in the Appalachian Basin and in markets availablethat are accessible through the Company's currentour transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States. The CompanyStates and Canada. We also contractscontract with certain processors to market a portion of NGLs on behalf of the Company. Similarly, revenues and related accounts receivable are generated from the gathering, transmission and storage of natural gas in the Appalachian Basin for independent producers, local distribution companies and marketers.our behalf.
No one lender of the large group of financial institutions in the syndicatessyndicate for the EQT, EQM or RMPour credit facilitiesfacility holds more than 10% of the respectivefinancial commitments under such facility. The large syndicate groupsgroup and relatively low percentage of participation by each lender are expected to limit the Company’s, EQM's and RMP'sour exposure to problemsdisruption or consolidation in the banking industry.
Item 8.Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of EQT Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, 20172020 and 2016,2019, the related statements of consolidated operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2017,2020, and the related notes and the financial statement schedule listed in the Index at Item 15 (a) (collectively referred to as the “financial statements”"consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 20172020 and 2016,2019, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017,2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 15, 201817, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Depreciation, depletion and amortization ('DD&A') of proved oil and natural gas properties
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| Description of the Matter | At December 31, 2020, the net book value of the Company's proved oil and natural gas properties was $13,613 million, and depreciation, depletion and amortization (DD&A) expense was $1,393 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A is recorded on a cost center basis using the units-of-production method. Proved developed reserves, as estimated by the Company’s internal engineers, are used to calculate depreciation of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by the Company’s engineers, are used to calculate depletion on property acquisitions. Proved natural gas, natural gas liquids (NGLs) and oil reserve estimates are based on geological and engineering evaluations of in-place hydrocarbon volumes. Significant judgment is required by the Company’s engineers in evaluating geological and engineering data when estimating proved natural gas, NGLs and oil reserves. Estimating reserves also requires the selection of inputs, including natural gas, NGLs and oil price assumptions, future operating and capital costs assumptions and tax rates by jurisdiction, among others. Because of the complexity involved in estimating natural gas, NGLs and oil reserves, management used independent engineers to audit the estimates prepared by the Company’s internal engineers as of December 31, 2020. Auditing the Company’s DD&A calculation is especially complex because of the use of the work of the internal engineers and the independent engineers and the evaluation of management’s determination of the inputs described above used by the specialists in estimating proved natural gas, NGLs and oil reserves. |
| |
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the specialists for use in estimating the proved natural gas, NGLs and oil reserves.
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff and the independent engineers used to audit the estimates. In addition, we evaluated the completeness and accuracy of the financial data and inputs described above used by the specialists in estimating proved natural gas, NGLs and oil reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management’s development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company’s drill plan and the availability of capital relative to the drill plan. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved natural gas, NGLs and oil reserves amounts used to the Company’s reserve report. |
Accounting for the Equitrans gas gathering agreement
| | | | | |
| Description of the Matter | As more fully described in Note 5 to the consolidated financial statements, on February 26, 2020, the Company entered into the Share Purchase Agreements and the Consolidated Gas Gathering Agreement (the Consolidated GGA) pursuant to which, among other things, the Company sold to Equitrans Midstream 50% of its ownership of Equitrans Midstream's common stock in exchange for approximately $52 million in cash and rate relief under certain of the Company's gathering contracts with EQM, an affiliate of Equitrans Midstream. The Consolidated GGA provides for additional cash bonus payments (the Henry Hub Cash Bonus) payable by the Company to EQM conditioned upon the quarterly average of the NYMEX Henry Hub natural gas settlement price exceeding certain price thresholds during a specified period. The Company’s initial entry to record this transaction included recognition of a contract asset representing the estimated fair value of the rate relief provided by the Consolidated GGA of $410 million and a derivative liability related to the Henry Hub Cash Bonus of approximately $117 million. The determination of fair value of these components included significant judgment and assumptions by management, including an estimated production volume forecast, future commodity prices and price volatility, and a market-based discount rate.
Auditing the Company's initial accounting for the Consolidated GGA contract asset and Henry Hub Cash Bonus derivative liability involved a high degree of subjectivity as the determination of fair values was based on assumptions as described above about future market and economic conditions. Additionally, a detailed analysis of the terms of the relevant agreements was required to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance. |
| |
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s accounting for the Consolidated GGA. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions outlined above that are inputs to the fair value calculations. We also tested management’s evaluation of the Consolidated GGA and the identification and evaluation of specific features and the related accounting.
To test the initial accounting for the Consolidated GGA, our audit procedures included, among others, inspection of the underlying agreement and testing management’s application of the relevant accounting guidance, including the determination of the balance sheet classification of each transaction component and the identification of any derivatives included in the arrangements. We involved professionals with specialized skill and knowledge to assist in evaluating the appropriateness of the accounting for the Consolidated GGA, including conclusions reached with respect to identification and bifurcation of embedded features. Our testing of the Company’s estimate of fair value of the contract asset and derivative liability related to the Henry Hub option included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit effort involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow models, as well as testing the significant market-related assumptions, such as future commodity prices and the market-based discount rate, used to develop the fair value estimates. |
Convertible Notes Issuance
| | | | | |
| Description of the Matter | As described in Note 10 to the consolidated financial statements, in April 2020, the Company issued $500 million of aggregate principal of 1.75% convertible senior notes due May 2026 in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. Additionally, the Company entered into separate capped call transactions to reduce potential dilution to the Company’s common stock upon any conversion of the Convertible Notes. These transactions are collectively referred to as the Convertible Notes Transactions. To account for the Convertible Notes, the Company was required to separate the Convertible Notes into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of similar debt instruments that do not have an associated conversion feature. The carrying amount of the equity component was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes.
Auditing the Company’s accounting for the Convertible Notes Transactions was complex due to the judgment that was required in determining the balance sheet classification of the elements of the Convertible Notes. Additionally, a detailed analysis of the terms of the Convertible Notes Transactions was required to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance. |
| |
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Convertible Notes Transactions. For example, we tested the Company's controls over the initial recognition and measurement of the Convertible Notes Transactions, including the recording of the associated liability and equity components. We also tested the evaluation of the Convertible Notes and the identification and evaluation of specific features and the related accounting.
To test the initial accounting for the Convertible Notes Transactions, our audit procedures included, among others, inspection of the agreements underlying the Convertible Notes Transactions and testing management’s application of the relevant accounting guidance, including the determination of the balance sheet classification of each transaction and the identification of any derivatives included in the arrangements. We involved professionals with specialized skill and knowledge to assist in evaluating the appropriateness of the accounting for the convertible notes, including conclusions reached with respect to identification and bifurcation of embedded features. |
Valuation of Acquired Proved Reserves
| | | | | |
| Description of the Matter | As described in Note 6 to the consolidated financial statements, the Company completed the acquisition of the Appalachian assets of Chevron U.S.A. during the year ended December 31, 2020. The Company’s accounting for the acquisition included determining the fair value of the acquired proved reserves. The determination of fair value of the acquired proved reserves included significant judgment and assumptions by management, including future commodity prices, anticipated production volumes, future operating costs, and a weighted average cost of capital (WACC).
Auditing the Company's valuation of acquired proved reserves involved a high degree of subjectivity as the determination of fair value was based on assumptions as described above about future market and economic conditions. In addition, the certain of the assumptions developed by the Company’s engineering staff in conjunction with the reserve estimates described in the preceding critical audit matter, are used as inputs in the cash flow model. |
| |
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company's process to estimate fair value for the acquired proved reserves. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions that are inputs to the fair value calculation and management’s review of the valuation model.
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff, the independent engineers used to audit the estimates, and the external valuation specialist used to assist with the determination of the fair value of certain acquired assets. Our testing of the Company’s estimate of fair value of the acquired proved reserves included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit effort involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow model, as well as testing the significant market-related assumptions described above used to develop the fair value estimate. We evaluated the reasonableness of management's assumptions by comparing the key market-related assumptions (including future natural gas prices and WACC rates) used in the cash flow model to external market and third-party data and anticipated production volumes to the reserve estimates audited by the independent engineers. |
/s/ Ernst & Young LLP
We have served as the Company’sCompany's auditor since 1950.
Pittsburgh, Pennsylvania
February 15, 201817, 2021
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of EQT Corporation
Opinion on Internal Control over Financial Reporting
We have audited EQT Corporation and subsidiaries’subsidiaries' internal control over financial reporting as of December 31, 2017,2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, EQT Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2020, based on the COSO criteria.
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Rice Energy Inc.,the assets acquired in the Chevron Acquisition, which isare included in the 20172020 consolidated financial statements of the Company and constituted 45% and 53%5% of total and net assets, respectively, as of December 31, 20172020, and 10% and 24%less than 1% of consolidated total operating revenues, and income before income taxes, respectively, for the year then ended.ended December 31, 2020. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Rice Energy Inc.assets acquired in the Chevron Acquisition.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of EQT Corporation and subsidiariesthe Company as of December 31, 20172020 and 2016,2019, and the related statements of consolidated operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 20172020 and the related notes and the financial statement schedule listed in the Index at Item 15 (a) of the Company and our report dated February 15, 201817, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 15, 201817, 2021
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
YEARS ENDED DECEMBER 31,
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (Thousands, except per share amounts) |
| Operating revenues: | | | | | |
| Sales of natural gas, natural gas liquids and oil | $ | 2,650,299 | | | $ | 3,791,414 | | | $ | 4,695,519 | |
| Gain (loss) on derivatives not designated as hedges | 400,214 | | | 616,634 | | | (178,591) | |
| Net marketing services and other | 8,330 | | | 8,436 | | | 40,940 | |
| Total operating revenues | 3,058,843 | | | 4,416,484 | | | 4,557,868 | |
| Operating expenses: | | | | | |
| Transportation and processing | 1,710,734 | | | 1,752,752 | | | 1,697,001 | |
| Production | 155,403 | | | 153,785 | | | 195,775 | |
| Exploration | 5,484 | | | 7,223 | | | 6,765 | |
| Selling, general and administrative | 174,769 | | | 170,611 | | | 232,543 | |
| Depreciation and depletion | 1,393,465 | | | 1,538,745 | | | 1,569,038 | |
| Amortization of intangible assets | 26,006 | | | 35,916 | | | 41,367 | |
| Impairment/loss on sale/exchange of long-lived assets | 100,729 | | | 1,138,287 | | | 2,709,976 | |
| Impairment of intangible and other assets | 34,694 | | | 15,411 | | | 0 | |
| Impairment of goodwill | 0 | | | 0 | | | 530,811 | |
| Impairment and expiration of leases | 306,688 | | | 556,424 | | | 279,708 | |
| Other operating expenses | 28,537 | | | 199,440 | | | 78,008 | |
| Total operating expenses | 3,936,509 | | | 5,568,594 | | | 7,340,992 | |
| Operating loss | (877,666) | | | (1,152,110) | | | (2,783,124) | |
| Gain on Equitrans Share Exchange (see Note 5) | (187,223) | | | 0 | | | 0 | |
| Loss on investment in Equitrans Midstream Corporation | 314,468 | | | 336,993 | | | 72,366 | |
| Dividend and other income | (35,512) | | | (91,483) | | | (7,017) | |
| Loss on debt extinguishment | 25,435 | | | 0 | | | 0 | |
| Interest expense | 271,200 | | | 199,851 | | | 228,958 | |
| Loss from continuing operations before income taxes | (1,266,034) | | | (1,597,471) | | | (3,077,431) | |
| Income tax benefit | (298,858) | | | (375,776) | | | (696,511) | |
| Loss from continuing operations | (967,176) | | | (1,221,695) | | | (2,380,920) | |
| Income from discontinued operations, net of tax | 0 | | | 0 | | | 373,762 | |
| Net loss | (967,176) | | | (1,221,695) | | | (2,007,158) | |
| Less: Net loss attributable to noncontrolling interest | (10) | | | 0 | | | 0 | |
| Less: Net income from discontinued operations attributable to noncontrolling interests | 0 | | | 0 | | | 237,410 | |
| Net loss attributable to EQT Corporation | $ | (967,166) | | | $ | (1,221,695) | | | $ | (2,244,568) | |
| | | | | |
| Amounts attributable to EQT Corporation: | | | | | |
| Loss from continuing operations | $ | (967,166) | | | $ | (1,221,695) | | | $ | (2,380,920) | |
| Income from discontinued operations, net of tax | 0 | | | 0 | | | 136,352 | |
| Net loss | $ | (967,166) | | | $ | (1,221,695) | | | $ | (2,244,568) | |
| | | | | |
| Loss per share of common stock attributable to EQT Corporation: | | | | | |
| Basic and diluted: | | | | | |
| Weighted average common stock outstanding | 260,613 | | | 255,141 | | | 260,932 | |
| Loss from continuing operations | $ | (3.71) | | | $ | (4.79) | | | $ | (9.12) | |
| Income from discontinued operations | 0 | | | 0 | | | 0.52 | |
| Net loss | $ | (3.71) | | | $ | (4.79) | | | $ | (8.60) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these Consolidated Financial Statements.
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (Thousands except per share amounts) |
| Revenues: | | | | | |
| Sales of natural gas, oil and NGLs | $ | 2,651,318 |
| | $ | 1,594,997 |
| | $ | 1,690,360 |
|
| Pipeline, water and net marketing services | 336,676 |
| | 262,342 |
| | 263,640 |
|
| Gain (loss) on derivatives not designated as hedges | 390,021 |
| | (248,991 | ) | | 385,762 |
|
| Total operating revenues | 3,378,015 |
| | 1,608,348 |
| | 2,339,762 |
|
| | | | | | |
| Operating expenses: | |
| | |
| | |
|
| Transportation and processing | 559,839 |
| | 365,817 |
| | 275,348 |
|
| Operation and maintenance | 88,866 |
| | 73,266 |
| | 69,760 |
|
| Production | 182,737 |
| | 174,826 |
| | 177,935 |
|
| Exploration | 25,117 |
| | 13,410 |
| | 61,970 |
|
| Selling, general and administrative | 262,664 |
| | 272,747 |
| | 249,925 |
|
| Depreciation, depletion and amortization | 1,077,559 |
| | 927,920 |
| | 819,216 |
|
| Impairment of long-lived assets | — |
| | 66,687 |
| | 122,469 |
|
| Acquisition costs | 237,312 |
| | — |
| | — |
|
| Amortization of intangible assets | 10,940 |
| | — |
| | — |
|
| Total operating expenses | 2,445,034 |
| | 1,894,673 |
| | 1,776,623 |
|
| | | | | | |
| Gain on sale / exchange of assets | — |
| | 8,025 |
| | — |
|
| Operating income (loss) | 932,981 |
| | (278,300 | ) | | 563,139 |
|
| | | | | | |
| Other income | 24,955 |
| | 31,693 |
| | 9,953 |
|
| Loss on debt extinguishment | 12,641 |
| | — |
| | — |
|
| Interest expense | 202,772 |
| | 147,920 |
| | 146,531 |
|
| Income (loss) before income taxes | 742,523 |
| | (394,527 | ) | | 426,561 |
|
| Income tax (benefit) expense | (1,115,619 | ) | | (263,464 | ) | | 104,675 |
|
| Net income (loss) | 1,858,142 |
| | (131,063 | ) | | 321,886 |
|
| Less: Net income attributable to noncontrolling interests | 349,613 |
| | 321,920 |
| | 236,715 |
|
| Net income (loss) attributable to EQT Corporation | $ | 1,508,529 |
| | $ | (452,983 | ) | | $ | 85,171 |
|
| | | | | | |
| Earnings per share of common stock attributable to EQT Corporation: | |
| | |
| | |
|
| Basic: | |
| | |
| | |
|
| Weighted average common stock outstanding | 187,380 |
| | 166,978 |
| | 152,398 |
|
| Net income (loss) | $ | 8.05 |
| | $ | (2.71 | ) | | $ | 0.56 |
|
| | | | | | |
| Diluted: | |
| | |
| | |
|
| Weighted average common stock outstanding | 187,727 |
| | 166,978 |
| | 152,939 |
|
| Net income (loss) | $ | 8.04 |
| | $ | (2.71 | ) | | $ | 0.56 |
|
See notes to consolidated financial statements.
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31,
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Net income (loss) | $ | 1,858,142 |
| | $ | (131,063 | ) | | $ | 321,886 |
|
| | | | | | |
| Other comprehensive loss, net of tax: | |
| | |
| | |
|
| Net change in cash flow hedges: | |
| | |
| | |
|
| Natural gas, net of tax benefit of ($3,191), ($36,296) and ($102,271) | (4,982 | ) | | (55,155 | ) | | (152,359 | ) |
| Interest rate, net of tax expense of $105, $104 and $100 | 144 |
| | 144 |
| | 144 |
|
| Pension and other post-retirement benefits liability adjustment, net of tax expense (benefit) of $193, $6,778 and ($564) | 338 |
| | 10,675 |
| | (901 | ) |
| Other comprehensive loss | (4,500 | ) | | (44,336 | ) | | (153,116 | ) |
| Comprehensive income (loss) | 1,853,642 |
| | (175,399 | ) | | 168,770 |
|
| Less: Comprehensive income attributable to noncontrolling interests | 349,613 |
| | 321,920 |
| | 236,715 |
|
| Comprehensive income (loss) attributable to EQT Corporation | $ | 1,504,029 |
| | $ | (497,319 | ) | | $ | (67,945 | ) |
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (Thousands) |
| Net loss | $ | (967,176) | | | $ | (1,221,695) | | | $ | (2,007,158) | |
| | | | | |
| Other comprehensive (loss) income, net of tax: | | | | | |
| Net change in cash flow hedges: | | | | | |
| Natural gas, net of tax expense: $2,584 in 2018 | 0 | | | 0 | | | (4,625) | |
| Interest rate, net of tax expense: $210 in 2019 and $80 in 2018 | 0 | | | 387 | | | 168 | |
| Other postretirement benefits liability adjustment, net of tax (benefit) expense: $(36), $150 and $510 | (156) | | | 316 | | | 606 | |
| Change in accounting principle | 0 | | | (496) | | | 0 | |
| Other comprehensive (loss) income | (156) | | | 207 | | | (3,851) | |
| Comprehensive loss | (967,332) | | | (1,221,488) | | | (2,011,009) | |
| Less: Comprehensive loss attributable to noncontrolling interest | (10) | | | 0 | | | 0 | |
| Less: Comprehensive income from discontinued operations attributable to noncontrolling interests | 0 | | | 0 | | | 237,410 | |
| Comprehensive loss attributable to EQT Corporation | $ | (967,322) | | | $ | (1,221,488) | | | $ | (2,248,419) | |
SeeThe accompanying notes to consolidated financial statements.are an integral part of these Consolidated Financial Statements.
EQT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
| | | | | | | | | | | |
| | 2020 | | 2019 |
| | (Thousands) |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 18,210 | | | $ | 4,596 | |
| Accounts receivable (less provision for doubtful accounts: $6,239 and $6,861) | 566,552 | | | 610,088 | |
| Derivative instruments, at fair value | 527,073 | | | 812,664 | |
| Income tax receivable | 0 | | | 298,854 | |
| Prepaid expenses and other | 103,615 | | | 28,653 | |
| Total current assets | 1,215,450 | | | 1,754,855 | |
| | | |
| Property, plant and equipment | 21,995,249 | | | 21,655,351 | |
| Less: Accumulated depreciation and depletion | 5,940,984 | | | 5,499,861 | |
| Net property, plant and equipment | 16,054,265 | | | 16,155,490 | |
| | | |
| Contract asset | 410,000 | | | 0 | |
| Investment in Equitrans Midstream Corporation | 203,380 | | | 676,009 | |
| Other assets | 230,374 | | | 222,873 | |
| Total assets | $ | 18,113,469 | | | $ | 18,809,227 | |
| | | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | | | |
| Current liabilities: | | | |
| Current portion of debt | $ | 154,161 | | | $ | 16,204 | |
| Accounts payable | 705,461 | | | 796,438 | |
| Derivative instruments, at fair value | 600,877 | | | 312,696 | |
| | | |
| Other current liabilities | 301,911 | | | 220,564 | |
| Total current liabilities | 1,762,410 | | | 1,345,902 | |
| | | |
| Credit facility borrowings | 300,000 | | | 294,000 | |
| Term Loan Facility borrowings | 0 | | | 999,353 | |
| Senior notes | 4,371,467 | | | 3,878,366 | |
| Note payable to EQM Midstream Partners, LP | 99,838 | | | 105,056 | |
| Deferred income taxes | 1,371,967 | | | 1,485,814 | |
| Other liabilities and credits | 945,057 | | | 897,148 | |
| Total liabilities | 8,850,739 | | | 9,005,639 | |
| | | |
| Shareholders' equity: | | | |
Common stock, 0 par value, shares authorized: 640,000 and 320,000, shares issued: 280,003 and 257,003 | 8,241,684 | | | 7,818,205 | |
| Treasury stock, shares at cost: 1,658 and 1,832 | (29,348) | | | (32,507) | |
| Retained earnings | 1,048,259 | | | 2,023,089 | |
| Accumulated other comprehensive loss | (5,355) | | | (5,199) | |
| Total common shareholders' equity | 9,255,240 | | | 9,803,588 | |
| Noncontrolling interests in consolidated subsidiaries | 7,490 | | | 0 | |
| Total equity | 9,262,730 | | | 9,803,588 | |
| Total liabilities and shareholders' equity | $ | 18,113,469 | | | $ | 18,809,227 | |
The accompanying notes are an integral part of these Consolidated Financial Statements.
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEARS ENDED DECEMBER 31,
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| (Thousands) |
| Cash flows from operating activities: | | | | | |
| Net loss | $ | (967,176) | | | $ | (1,221,695) | | | $ | (2,007,158) | |
| Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | |
| Deferred income tax expense (benefit) | (155,840) | | | (275,063) | | | (510,405) | |
| Depreciation and depletion | 1,393,465 | | | 1,538,745 | | | 1,729,739 | |
| Amortization of intangible assets | 26,006 | | | 35,916 | | | 77,374 | |
| Impairment/loss on sale/exchange of long-lived assets and leases | 442,111 | | | 1,710,122 | | | 2,989,684 | |
| Gain on Equitrans Share Exchange | (187,223) | | | 0 | | | 0 | |
| Impairment of goodwill | 0 | | | 0 | | | 798,689 | |
| Loss on investment in Equitrans Midstream Corporation | 314,468 | | | 336,993 | | | 72,366 | |
| Loss on debt extinguishment | 25,435 | | | 0 | | | 0 | |
| Share-based compensation expense | 19,552 | | | 31,233 | | | 25,189 | |
| Amortization, accretion and other | 37,414 | | | 23,296 | | | (33,039) | |
| (Gain) loss on derivatives not designated as hedges | (400,214) | | | (616,634) | | | 178,591 | |
| Cash settlements received (paid) on derivatives not designated as hedges | 897,190 | | | 246,639 | | | (225,279) | |
| Net premiums (paid) received on derivative instruments | (46,665) | | | 22,616 | | | 0 | |
| Changes in other assets and liabilities: | | | | | |
| Accounts receivable | (36,296) | | | 432,323 | | | (439,062) | |
| Accounts payable | (29,193) | | | (238,674) | | | 457,113 | |
| Income tax receivable and payable | 322,763 | | | (167,281) | | | (117,188) | |
| Other current assets | (68,628) | | | 54,776 | | | (28,256) | |
| Other items, net | (49,468) | | | (61,608) | | | 7,898 | |
| Net cash provided by operating activities | 1,537,701 | | | 1,851,704 | | | 2,976,256 | |
| Cash flows from investing activities: | | | | | |
| Capital expenditures | (1,042,231) | | | (1,602,454) | | | (2,999,037) | |
| Cash paid for acquisitions (see Note 6) | (691,942) | | | 0 | | | 0 | |
| Capital expenditures for discontinued operations | 0 | | | 0 | | | (732,727) | |
| | | | | |
| Capital contributions to Mountain Valley Pipeline, LLC | 0 | | | 0 | | | (820,943) | |
| Proceeds from sale of assets | 126,080 | | | 0 | | | 583,381 | |
| Cash received for Equitrans Share Exchange | 52,323 | | | 0 | | | 0 | |
| Other investing activities | (30) | | | 1,312 | | | (9,778) | |
| Net cash used in investing activities | (1,555,800) | | | (1,601,142) | | | (3,979,104) | |
| Cash flows from financing activities: | | | | | |
| Net proceeds from issuance of common stock | 340,923 | | | 0 | | | 0 | |
| Proceeds from borrowings on credit facility | 3,118,250 | | | 2,978,750 | | | 8,637,500 | |
| Repayment of borrowings on credit facility | (3,112,250) | | | (3,484,750) | | | (8,953,500) | |
| Proceeds from issuance of debt | 2,600,000 | | | 1,000,000 | | | 2,500,000 | |
| Debt issuance costs and Capped Call Transactions (See Note 10) | (71,056) | | | (913) | | | (40,966) | |
| Repayments and retirements of debt | (2,822,262) | | | (704,661) | | | (8,376) | |
| Premiums paid on debt extinguishment | (21,132) | | | 0 | | | 0 | |
| Dividends paid | (7,664) | | | (30,655) | | | (31,375) | |
| Proceeds and excess tax benefits from awards under employee compensation plans | 0 | | | 0 | | | 1,946 | |
| Cash paid for taxes related to net settlement of share-based incentive awards | (596) | | | (7,224) | | | (22,647) | |
| Repurchase and retirement of common stock | 0 | | | 0 | | | (538,876) | |
| Repurchase of common stock | 0 | | | 0 | | | (27) | |
| Contributions from (distributions to) noncontrolling interests | 7,500 | | | 0 | | | (380,651) | |
| Acquisition of 25% of Strike Force Midstream LLC | 0 | | | 0 | | | (175,000) | |
| Net cash transferred at Separation and Distribution | 0 | | | 0 | | | (129,008) | |
| Net cash provided by (used in) financing activities | 31,713 | | | (249,453) | | | 859,020 | |
| Net change in cash and cash equivalents | 13,614 | | | 1,109 | | | (143,828) | |
| Cash and cash equivalents at beginning of year | 4,596 | | | 3,487 | | | 147,315 | |
| Cash and cash equivalents at end of year | $ | 18,210 | | | $ | 4,596 | | | $ | 3,487 | |
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Cash flows from operating activities: | |
| | |
| | |
|
| Net income (loss) | $ | 1,858,142 |
| | $ | (131,063 | ) | | $ | 321,886 |
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |
| | |
| | |
|
| Deferred income taxes | (1,050,612 | ) | | (180,261 | ) | | 17,876 |
|
| Depreciation, depletion and amortization | 1,077,559 |
| | 927,920 |
| | 819,216 |
|
| Amortization of intangibles | 10,940 |
| | — |
| | — |
|
| Asset and lease impairments and exploratory well costs | 20,327 |
| | 75,434 |
| | 182,242 |
|
| Gain on sale / exchange of assets | — |
| | (8,025 | ) | | — |
|
| Loss on debt extinguishment | 12,641 |
| | — |
| | — |
|
| (Recoveries of) provision for losses on accounts receivable | (979 | ) | | 3,856 |
| | (1,903 | ) |
| Other income | (24,955 | ) | | (31,693 | ) | | (9,953 | ) |
| Stock-based compensation expense | 94,592 |
| | 44,605 |
| | 58,629 |
|
| (Gain) loss on derivatives not designated as hedges | (390,021 | ) | | 248,991 |
| | (385,762 | ) |
| Cash settlements received on derivatives not designated as hedges | 40,728 |
| | 279,425 |
| | 172,093 |
|
| Pension settlement charge | — |
| | 9,403 |
| | — |
|
| Changes in other assets and liabilities: | |
| | |
| | |
|
| Excess tax benefits on stock-based compensation | — |
| | (1,148 | ) | | (22,945 | ) |
| Accounts receivable | (8,979 | ) | | (165,507 | ) | | 131,031 |
|
| Accounts payable | (16,680 | ) | | 40,548 |
| | (37,623 | ) |
| Other items, net | 14,995 |
| | (48,165 | ) | | (27,847 | ) |
| Net cash provided by operating activities | 1,637,698 |
| | 1,064,320 |
| | 1,216,940 |
|
| | | | | | |
| Cash flows from investing activities: | |
| | |
| | |
|
| Capital expenditures | (1,939,202 | ) | | (1,538,125 | ) | | (2,434,018 | ) |
| Cash payments for Rice Merger (as defined in Note 2), net of cash acquired | (1,560,272 | ) | | — |
| | — |
|
| Capital expenditures for other acquisitions | (818,957 | ) | | (1,051,239 | ) | | — |
|
| Investments in trading securities | — |
| | (288,772 | ) | | — |
|
| Sales of investments in trading securities | 283,758 |
| | 3,890 |
| | — |
|
| Dry hole costs | (11,420 | ) | | (1,369 | ) | | (17,130 | ) |
| Capital contributions to Mountain Valley Pipeline, LLC | (159,550 | ) | | (98,399 | ) | | (84,182 | ) |
| Sales of interests in Mountain Valley Pipeline, LLC | — |
| | 12,533 |
| | 9,723 |
|
| Restricted cash, net | 75,000 |
| | (75,000 | ) | | — |
|
| Proceeds from sale of assets | 3,573 |
| | 75,000 |
| | — |
|
| Net cash used in investing activities | (4,127,070 | ) | | (2,961,481 | ) | | (2,525,607 | ) |
| | | | | | |
| Cash flows from financing activities: | |
| | |
| | |
|
| Proceeds from the issuance of common shares of EQT Corporation, net of issuance costs | — |
| | 1,225,999 |
| | — |
|
| Proceeds from the issuance of common units of EQT Midstream Partners, LP, net of issuance costs | — |
| | 217,102 |
| | 1,182,002 |
|
| Proceeds from the sale of common units of EQT GP Holdings, LP, net of issuance costs | — |
| | — |
| | 673,964 |
|
| Proceeds from issuance of debt | 3,000,000 |
| | 500,000 |
| | — |
|
| Increase in borrowings on credit facilities | 2,063,000 |
| | 740,000 |
| | 617,000 |
|
| Repayment of borrowings on credit facilities | (1,076,500 | ) | | (1,039,000 | ) | | (318,000 | ) |
| Dividends paid | (20,827 | ) | | (20,156 | ) | | (18,310 | ) |
| Distributions to noncontrolling interests | (236,123 | ) | | (189,981 | ) | | (121,759 | ) |
| Contribution to Strike Force Midstream by minority owner, net of distribution | 6,738 |
| | — |
| | — |
|
| Repayments and retirements of debt | (2,000,000 | ) | | (5,119 | ) | | (169,004 | ) |
| Proceeds and excess tax benefits from awards under employee compensation plans | 244 |
| | 6,165 |
| | 36,965 |
|
| Cash paid for taxes related to net settlement of share-based incentive awards | (72,116 | ) | | (26,931 | ) | | (47,013 | ) |
| Debt issuance costs and revolving credit facility origination fees | (41,876 | ) | | (8,580 | ) | | — |
|
| Premiums paid on debt extinguishment | (89,363 | ) | | — |
| | — |
|
| Repurchase of common stock | (30 | ) | | (30 | ) | | (3,375 | ) |
| Net cash provided by financing activities | 1,533,147 |
| | 1,399,469 |
| | 1,832,470 |
|
| Net change in cash and cash equivalents | (956,225 | ) | | (497,692 | ) | | 523,803 |
|
| Cash and cash equivalents at beginning of year | 1,103,540 |
| | 1,601,232 |
| | 1,077,429 |
|
| Cash and cash equivalents at end of year | $ | 147,315 |
| | $ | 1,103,540 |
| | $ | 1,601,232 |
|
| | | | | | |
| Cash paid (received) during the year for: | |
| | |
| | |
|
| Interest, net of amount capitalized | $ | 189,371 |
| | $ | 144,657 |
| | $ | 147,550 |
|
| Income taxes, net | $ | 3,637 |
| | $ | (41,142 | ) | | $ | 95,708 |
|
SeeThe accompanying notes to consolidated financial statements. are an integral part of these Consolidated Financial Statements.
See Note 1 for supplemental cash flow information.
EQT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
See Note 8 for discontinued operations cash flow information.
|
| | | | | | | |
| | 2017 | | 2016 |
| | (Thousands) |
| Assets | |
| | |
|
| Current assets: | |
| | |
|
| Cash and cash equivalents | $ | 147,315 |
| | $ | 1,103,540 |
|
| Trading securities | — |
| | 286,396 |
|
| Accounts receivable (less accumulated provision for doubtful accounts: $8,226 in 2017; $6,923 in 2016) | 725,236 |
| | 341,628 |
|
| Derivative instruments, at fair value | 241,952 |
| | 33,053 |
|
| Prepaid expenses and other | 48,552 |
| | 63,602 |
|
| Total current assets | 1,163,055 |
| | 1,828,219 |
|
| | | | |
| Property, plant and equipment | 30,990,309 |
| | 18,216,775 |
|
| Less: accumulated depreciation and depletion | 6,105,294 |
| | 5,054,559 |
|
| Net property, plant and equipment | 24,885,015 |
| | 13,162,216 |
|
| | | | |
| Restricted cash | — |
| | 75,000 |
|
| Intangible assets, net | 736,360 |
| | — |
|
| Goodwill | 1,998,726 |
| | — |
|
| Investment in unconsolidated entity | 460,546 |
| | 184,562 |
|
| Other assets | 278,902 |
| | 222,925 |
|
| Total assets | $ | 29,522,604 |
| | $ | 15,472,922 |
|
EQT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
|
| | | | | | | |
| | 2017 | | 2016 |
| | (Thousands) |
| Liabilities and Shareholders’ Equity | |
| | |
|
| Current liabilities: | |
| | |
|
| Current portion of Senior Notes | $ | 7,999 |
| | $ | — |
|
| Accounts payable | 654,624 |
| | 309,978 |
|
| Derivative instruments, at fair value | 139,089 |
| | 257,943 |
|
| Other current liabilities | 430,525 |
| | 236,719 |
|
| Total current liabilities | 1,232,237 |
| | 804,640 |
|
| | | | |
| Credit facility borrowings | 1,761,000 |
| | — |
|
| Senior Notes | 5,562,555 |
| | 3,289,459 |
|
| Deferred income taxes | 1,768,900 |
| | 1,760,004 |
|
| Other liabilities and credits | 783,299 |
| | 499,572 |
|
| Total liabilities | 11,107,991 |
| | 6,353,675 |
|
| | | | |
| Equity: | |
| | |
|
| Shareholders’ equity | |
| | |
|
| Common stock, no par value, authorized 320,000 shares, shares issued: 267,871 in 2017 and 177,896 in 2016 | 9,388,903 |
| | 3,440,185 |
|
| Treasury stock, shares at cost: 3,551 in 2017 (including 253 held in rabbi trust) and 5,069 in 2016 (including 226 held in rabbi trust) | (63,602 | ) | | (91,019 | ) |
| Retained earnings | 3,996,775 |
| | 2,509,073 |
|
| Accumulated other comprehensive (loss) income | (2,458 | ) | | 2,042 |
|
| Total common shareholders’ equity | 13,319,618 |
| | 5,860,281 |
|
| Noncontrolling interests in consolidated subsidiaries | 5,094,995 |
| | 3,258,966 |
|
| Total equity | 18,414,613 |
| | 9,119,247 |
|
| Total liabilities and equity | $ | 29,522,604 |
| | $ | 15,472,922 |
|
See notes to consolidated financial statements.
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED EQUITY
YEARS ENDED DECEMBER 31, 2017, 20162020, 2019 and 20152018
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | | | | | Accumulated Other
Comprehensive (Loss) Income | | Noncontrolling Interests in
Consolidated Subsidiaries | | |
| | Shares | | No Par Value | | Treasury Stock | | Retained Earnings | | | | Total Equity |
| | (Thousands, except per share or unit amounts) |
| Balance at December 31, 2017 | 264,320 | | | $ | 9,388,903 | | | $ | (63,602) | | | $ | 3,996,775 | | | $ | (2,458) | | | $ | 5,094,995 | | | $ | 18,414,613 | |
| Comprehensive (loss) income, net of tax: | | | | | | | | | | | | | |
| Net (loss) income | | | | | | | (2,244,568) | | | | | 237,410 | | | (2,007,158) | |
| Net change in cash flow hedges: | | | | | | | | | | | | | |
| Natural gas, net of tax: $2,584 | | | | | | | | | (4,625) | | | | | (4,625) | |
| Interest rate, net of tax: $80 | | | | | | | | | 168 | | | | | 168 | |
| Other postretirement benefits liability adjustment, net of tax: $510 | | | | | | | | | 606 | | | | | 606 | |
| Dividends ($0.12 per share) | | | | | | | (31,375) | | | | | | | (31,375) | |
| Share-based compensation plans, net | 798 | | | (6,976) | | | 14,408 | | | | | | | 953 | | | 8,385 | |
| Distributions to noncontrolling interests in discontinued operations (a) | | | | | | | | | | | (380,651) | | | (380,651) | |
| Change in accounting principle | | | | | | | 4,113 | | | | | | | 4,113 | |
| Repurchase and retirement of common stock | (10,646) | | | (538,876) | | | | | | | | | | | (538,876) | |
| Purchase of Strike Force Midstream LLC noncontrolling interests | | | 1,818 | | | | | | | | | (176,818) | | | (175,000) | |
| Changes in ownership of consolidated subsidiaries | | | (158,560) | | | | | | | | | 214,930 | | | 56,370 | |
| Distribution of Equitrans Midstream Corporation | | | (857,755) | | | | | 1,459,330 | | | 903 | | | (4,990,819) | | | (4,388,341) | |
| Balance at December 31, 2018 | 254,472 | | | $ | 7,828,554 | | | $ | (49,194) | | | $ | 3,184,275 | | | $ | (5,406) | | | $ | 0 | | | $ | 10,958,229 | |
| Comprehensive (loss) income, net of tax: | | | | | | | | | | | | | |
| Net loss | | | | | | | (1,221,695) | | | | | | | (1,221,695) | |
| Net change in interest rate cash flow hedges, net of tax: $210 | | | | | | | | | 387 | | | | | 387 | |
| Other postretirement benefits liability adjustment, net of tax: $150 | | | | | | | | | 316 | | | | | 316 | |
| Dividends ($0.12 per share) | | | | | | | (30,655) | | | | | | | (30,655) | |
| Share-based compensation plans | 921 | | | 6,355 | | | 16,687 | | | | | | | | | 23,042 | |
| Change in accounting principle | | | | | | | 496 | | | (496) | | | | | — | |
| Distribution of Equitrans Midstream Corporation (see Note 9) | | | (2,234) | | | | | 93,123 | | | | | | | 90,889 | |
| Other | (222) | | | (14,470) | | | | | (2,455) | | | | | | | (16,925) | |
| Balance at December 31, 2019 | 255,171 | | | $ | 7,818,205 | | | $ | (32,507) | | | $ | 2,023,089 | | | $ | (5,199) | | | $ | 0 | | | $ | 9,803,588 | |
| Comprehensive loss, net of tax: | | | | | | | | | | | | | |
| Net loss | | | | | | | (967,166) | | | | | (10) | | | (967,176) | |
| Other postretirement benefits liability adjustment, net of tax: $(36) | | | | | | | | | (156) | | | | | (156) | |
| Dividends ($0.03 per share) | | | | | | | (7,664) | | | | | | | (7,664) | |
| Share-based compensation plans | 174 | | | 18,911 | | | 3,159 | | | | | | | | | 22,070 | |
| Equity component of convertible senior notes (see Note 10) | | | 63,645 | | | | | | | | | | | 63,645 | |
| Issuance of common shares | 23,000 | | | 340,923 | | | | | | | | | | | 340,923 | |
| Contributions from noncontrolling interests | | | | | | | | | | | 7,500 | | | 7,500 | |
| Balance at December 31, 2020 | 278,345 | | | $ | 8,241,684 | | | $ | (29,348) | | | $ | 1,048,259 | | | $ | (5,355) | | | $ | 7,490 | | | $ | 9,262,730 | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | | | | | | | |
| | Shares
Outstanding | | No
Par Value | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Noncontrolling
Interests in
Consolidated
Subsidiaries | | Total
Equity |
| | | | | | (Thousands) | | | | |
| Balance, December 31, 2014 | 151,596 |
| | $ | 1,466,192 |
| | $ | 2,917,129 |
| | $ | 199,494 |
| | $ | 1,790,248 |
| | $ | 6,373,063 |
|
| Comprehensive income (net of tax): | |
| | |
| | |
| | |
| | |
| | |
|
| Net income | |
| | |
| | 85,171 |
| | |
| | 236,715 |
| | 321,886 |
|
| Net change in cash flow hedges: | |
| | |
| | |
| | |
| | |
| | |
|
| Natural gas, net of tax of ($102,271) | |
| | |
| | |
| | (152,359 | ) | | |
| | (152,359 | ) |
| Interest rate, net of tax of $100 | |
| | |
| | |
| | 144 |
| | |
| | 144 |
|
| Pension and other post-retirement benefits liability adjustment, net of tax of ($564) | |
| | |
| | |
| | (901 | ) | | |
| | (901 | ) |
| Dividends ($0.12 per share) | |
| | |
| | (18,310 | ) | | |
| | |
| | (18,310 | ) |
| Stock-based compensation plans, net | 996 |
| | 77,378 |
| | |
| | |
| | 1,056 |
| | 78,434 |
|
| Distributions to noncontrolling interests ($2.505 and $0.15139 per common unit for EQT Midstream Partners, LP and EQT GP Holdings, LP, respectively) | | | | | | | | | (121,759 | ) | | (121,759 | ) |
| Sale of common units of EQT GP Holdings, LP | | | | | | | | | 673,964 |
| | 673,964 |
|
| Issuance of common units of EQT Midstream Partners, LP | | | | | | | | | 1,182,002 |
| | 1,182,002 |
|
| Changes in ownership of consolidated subsidiaries | | | 507,228 |
| | | | | | (811,975 | ) | | (304,747 | ) |
| Repurchase and retirement of common stock | (38 | ) | | (1,597 | ) | | $ | (1,778 | ) | | | | | | (3,375 | ) |
| Balance, December 31, 2015 | 152,554 |
| | $ | 2,049,201 |
| | $ | 2,982,212 |
| | $ | 46,378 |
| | $ | 2,950,251 |
| | $ | 8,028,042 |
|
| Comprehensive income (net of tax): | |
| | |
| | |
| | |
| | |
| | |
|
| Net (loss) income | |
| | |
| | (452,983 | ) | | |
| | 321,920 |
| | (131,063 | ) |
| Net change in cash flow hedges: | |
| | |
| | |
| | |
| | |
| | |
|
| Natural gas, net of tax of ($36,296) | |
| | |
| | |
| | (55,155 | ) | | |
| | (55,155 | ) |
| Interest rate, net of tax of $104 | |
| | |
| | |
| | 144 |
| | |
| | 144 |
|
| Pension and other post-retirement benefits liability adjustment, net of tax of $6,778 | |
| | |
| | |
| | 10,675 |
| | |
| | 10,675 |
|
| Dividends ($0.12 per share) | |
| | |
| | (20,156 | ) | | |
| | |
| | (20,156 | ) |
| Stock-based compensation plans, net | 724 |
| | 42,782 |
| | |
| | |
| | 161 |
| | 42,943 |
|
| Distributions to noncontrolling interests ($3.05 and $0.571 per common unit for EQT Midstream Partners, LP and EQT GP Holdings, LP, respectively) | |
| | |
| | |
| | |
| | (189,981 | ) | | (189,981 | ) |
| Issuance of common shares of EQT Corporation | 19,550 |
| | 1,225,999 |
| | | | | | | | 1,225,999 |
|
| Issuance of common units of EQT Midstream Partners, LP | |
| | |
| | |
| | |
| | 217,102 |
| | 217,102 |
|
| Elimination of deferred taxes | | | 5,921 |
| | | | | |
|
| | 5,921 |
|
| Changes in ownership of consolidated subsidiaries | | | 25,293 |
| | | | | | (40,487 | ) | | (15,194 | ) |
| Repurchase and retirement of common stock | (1 | ) | | (30 | ) | |
|
| | |
| | |
| | (30 | ) |
| Balance, December 31, 2016 | 172,827 |
| | $ | 3,349,166 |
| | $ | 2,509,073 |
| | $ | 2,042 |
| | $ | 3,258,966 |
| | $ | 9,119,247 |
|
| Comprehensive income (net of tax): | |
| | |
| | |
| | |
| | |
| | |
|
| Net income | |
| | |
| | 1,508,529 |
| | |
| | 349,613 |
| | 1,858,142 |
|
| Net change in cash flow hedges: | |
| | |
| | |
| | |
| | |
| | |
|
| Natural gas, net of tax of ($3,191) | |
| | |
| | |
| | (4,982 | ) | | |
| | (4,982 | ) |
| Interest rate, net of tax of $105 | |
| | |
| | |
| | 144 |
| | |
| | 144 |
|
| Pension and other post-retirement benefits liability adjustment, net of tax of $193 | |
| | |
| | |
| | 338 |
| | |
| | 338 |
|
| Dividends ($0.12 per share) | |
| | |
| | (20,827 | ) | | |
| | |
| | (20,827 | ) |
| Stock-based compensation plans, net | 580 |
| | 26,436 |
| | |
| | |
| | 190 |
| | 26,626 |
|
| Distributions to noncontrolling interests ($3.655 and $0.806 per common unit for EQT Midstream Partners, LP and EQT GP Holdings, LP, respectively) | |
| | |
| | |
| | |
| | (236,123 | ) | | (236,123 | ) |
| Rice Merger, net of withholdings | 90,914 |
| | 5,949,729 |
| | | | | | 1,715,611 |
| | 7,665,340 |
|
| Contribution from noncontrolling interest, net of distribution | | | | | | | | | 6,738 |
| | 6,738 |
|
Repurchase of common stock
| (1 | ) | | (30 | ) | | | | | | | | (30 | ) |
| Balance, December 31, 2017 | 264,320 |
| | $ | 9,325,301 |
| | $ | 3,996,775 |
| | $ | (2,458 | ) | | $ | 5,094,995 |
| | $ | 18,414,613 |
|
Common shares authorized: 320,000 shares. at December 31, 2018 and 2019 and 640,000 at December 31, 2020.
Preferred shares authorized: 3,000 shares.3,000. There are nowere 0 preferred shares issued or outstanding.
See
(a)For the year ended December 31, 2018, distributions to noncontrolling interests were $4.295, $1.123 and $0.5966 per common unit for EQM Midstream Partners, LP, EQGP Holdings, LP and RM Partners LP, respectively.
The accompanying notes to consolidated financial statements.are an integral part of these Consolidated Financial Statements.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 20172020
1.Summary of Significant Accounting Policies
Principles of Consolidation:Consolidation. The Consolidated Financial Statements include the accounts of EQT Corporation and all subsidiaries, ventures and partnerships in which EQT holds a controlling interest is held (EQT(collectively, EQT or the Company). All significant intercompanyIntercompany accounts and transactions have been eliminated in consolidation. The Company records noncontrolling interest in its financial statementsConsolidated Financial Statements for any non-wholly ownednon-wholly-owned consolidated subsidiary.
Segments: Operating segments are revenue-producing componentsInvestment in Consolidated Partnership. In the fourth quarter of the enterprise for which separate financial information is produced internally and which are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources.
Prior to the Rice Merger (as defined in Note 2),2020, the Company reported its results of operations through three business segments: EQT Production, EQT Gathering and EQT Transmission. These reporting segments reflectedentered into a partnership with a third-party investor (the Partnership). Because the Company's lines of business and were reportedCompany has the power to direct the activities that most significantly affect the Partnership's economic performance, the Company consolidates the Partnership. The Company presents noncontrolling interest in the same manner in which the Company evaluated its operating performance through September 30, 2017. Following the Rice Merger, the Company adjusted its internal reporting structure to incorporate the newly acquired assets. The Company now conducts its business through five business segments: EQT Production, EQM Gathering (formerly knownPartnership as EQT Gathering), EQM Transmission (formerly known as EQT Transmission), RMP Gathering and RMP Water. The EQT Production segment incorporates the Company’s production activities, including those acquireda component of equity in the Rice Merger, the Company's marketing operations,Consolidated Balance Sheet and certain gathering operations primarily supporting the Company's production activities. The EQM Gathering segment contains the Company's gathering assets that are owned by EQT Midstream Partners, LP (EQM), and the EQM Transmission segment includes the Company's Federal Energy Regulatory Commission (FERC)-regulated interstate pipeline and storage operations, which are owned by EQM. Therefore, the financial and operational disclosures related to EQM Gathering and EQM Transmission in this Annual Report on Form 10-K are the same as EQM’s disclosures in its Annual Report on Form 10-K for the year ended December 31, 2017. The RMP Gathering segment contains the Company's gathering assets that are owned by Rice Midstream Partners, LP (RMP). The RMP Water segment contains the Company's water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities owned by RMP. The financial and operational disclosures related to RMP Gathering and RMP Water will be the same as RMP’s successor disclosures for the period subsequent to the Rice Merger in its Annual Report on Form 10-K for the year ended December 31, 2017.
Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income. Other income, interest and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon an allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocatedearnings attributable to the noncontrolling interest in the Statement of Consolidated Operations.
Segments. The Company's operations consist of 1 reportable segment. The Company has a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments.
The Company measures financial performance as a single enterprise and not on an area-by-area basis. Substantially all of the Company’sCompany's operating revenues, income from operations and assets are generated orand located in the United States.
Reclassification. Certain previously reported amounts have been reclassified to conform to the current year presentation.
Discontinued Operations. For businesses classified as discontinued operations, balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities of discontinued operations in the Consolidated Balance Sheet and discontinued operations on the Statement of Consolidated Operations, respectively. The Statement of Consolidated Cash Flows was not reclassified for discontinued operations. See Note 8.
Use of Estimates:Estimates. The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates.
Cash Equivalents:and Cash Equivalents. The Company considers all highly liquidhighly-liquid investments with an original maturity of three months or less when purchased to be cash equivalents. Theseequivalents and accounts for such investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest expense. At December 31, 2016, the Company held two certificates of deposit (CDs) in denominations greater than $0.1 million with an aggregate carrying value of $300.0 million. These CDs matured in January 2017.
Trading Securities: Trading securities consist of liquid debt securities that are carried at fair value. Realized losses of $2.6 million and unrealized gains of $1.5 million on these debt securities are included in other income in the Statements of Consolidated Operations for the years ended December 31, 2017 and 2016, respectively. At December 31, 2016, investments in trading securities had a fair value of $286.4 million.Accounts Receivable. The Company initiated its investments in trading securities in 2016 to enhance returns on a portion of its significant cash balance at that time. Investments within the Company's portfolio are subject to a minimum credit rating based on type of investment, and the portfolio's asset mix is subject to exposure limits to ensure issuer and asset class diversification. As of March 31, 2017, the Company closed its positions on all trading securities.
Accounts Receivable: Accountsaccounts receivable relates primarily relate to the sales of natural gas, oilnatural gas liquids (NGLs) and NGLsoil and amounts due from joint interest partners. Natural gas, oil and NGLs sales receivables were $516.7 million and $316.9 million at December 31, 2017 and 2016, respectively. Joint interest receivables were $149.3 million and $1.1 million at December 31, 2017 and 2016, respectively.See Note 2 for a discussion of amounts due from contracts with customers.
Restricted Cash: During 2016, the Company placed $75.0 millionDerivative Instruments. See Note 3 for a discussion of the proceeds received fromCompany's derivative instruments and Note 4 for a discussion of the saleCompany's fair value hierarchy and fair value measurements.
Prepaid Expenses and Other. The following table summarizes the Company's prepaid expenses and other current assets.
| | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| | (Thousands) |
| Margin requirements with counterparties (See Note 3) | $ | 82,552 | | | $ | 12,606 | |
| Prepaid expenses and other current assets | 21,063 | | | 16,047 | |
| Total prepaid expenses and other | $ | 103,615 | | | $ | 28,653 | |
Inventories: Generally, the Company’s inventory balance consists of natural gas stored underground or in pipelines and materials and supplies recorded at the lower of average cost or market. During the years ended December 31, 2017, 2016 and 2015, the Company recorded no lower of cost or market adjustments related to inventory.
Property, Plant and Equipment:Equipment. The Company’sfollowing table summarizes the Company's property, plant and equipment consist of the following:equipment.
| | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| | (Thousands) |
| Oil and gas producing properties, successful efforts method | $ | 21,771,025 | | | $ | 21,316,834 | |
| Less: Accumulated depreciation and depletion | 5,866,418 | | | 5,402,515 | |
| Net oil and gas producing properties | 15,904,607 | | | 15,914,319 | |
| Other properties, at cost less accumulated depreciation | 149,658 | | | 241,171 | |
| Net property, plant and equipment | $ | 16,054,265 | | | $ | 16,155,490 | |
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (Thousands) |
| Oil and gas producing properties, successful efforts method | $ | 23,937,154 |
| | $ | 13,878,659 |
|
| Accumulated depreciation and depletion | (5,121,646 | ) | | (4,217,154 | ) |
| Net oil and gas producing properties | 18,815,508 |
| | 9,661,505 |
|
| Gathering assets | 2,765,763 |
| | 1,330,998 |
|
| Accumulated depreciation and amortization | (151,595 | ) | | (110,473 | ) |
| Net gathering assets | 2,614,168 |
| | 1,220,525 |
|
| Transmission assets | 1,674,080 |
| | 1,563,860 |
|
| Accumulated depreciation and amortization | (248,474 | ) | | (205,551 | ) |
| Net transmission assets | 1,425,606 |
| | 1,358,309 |
|
| Water service assets | 193,825 |
| | — |
|
| Accumulated depreciation and amortization | (3,363 | ) | | — |
|
| Net water service assets | 190,462 |
| | — |
|
| Other properties, at cost less accumulated depreciation (a) | 1,839,271 |
| | 921,877 |
|
| Net property, plant and equipment | $ | 24,885,015 |
| | $ | 13,162,216 |
|
(a) Other properties includes gathering assets owned by EQT Production and shared assets held at Headquarters.
The Company uses the successful efforts method of accounting for oilgas, NGL and gasoil producing activities. Under this method, the cost of productive wells and related equipment, development dry holes as well asand productive acreage, including productive mineral interests, are capitalized and depleted using the unit-of-production method. These capitalized costs include salaries, benefits and other internal costs directly attributable to theseproduction activities. The Company capitalized internal costs of $114.6approximately $51 million, $115.4$77 million and $114.4$130 million in 2017, 20162020, 2019 and 2015, respectively, for production related activities.2018, respectively. The Company also capitalized $20.5 million, $19.2 million and $35.8 million of interest expense related to Marcellus, Upper Devonian and Utica well development of approximately $17 million, $24 million and $29 million in 2017, 20162020, 2019 and 2015,2018, respectively. Depletion expense is calculated based on the actual produced sales volumes multiplied by the applicable depletion rate per unit. The depletionDepletion rates for leases and wells are derivedeach calculated by dividing the net capitalized costs by the number of units expected to be produced over the life of the reserves for lease costs and well costs separately. Costs offor exploratory dry holes, exploratory geological and geophysical activities and delay rentals andas well as other property carrying costs are charged to exploration expense. The majority of the Company’sCompany's producing oil and gas properties were depleted athad an overall average depletion rate of $1.04 per Mcfe, $1.06 per Mcfe$0.92, $1.01 and $1.18$1.04 per Mcfe for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively.
There were 0 exploratory wells drilled during 2020, 2019 and 2018, and there were 0 capitalized exploratory well costs for the years ended December 31, 2020, 2019 and 2018.
Impairment of Long-lived Assets. The carrying values of the Company’sCompany's proved oil and gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. In order toTo determine whether impairment of the Company's oil and gas properties has occurred, the Company estimatescompares the estimated expected undiscounted future cash flows (on an undiscounted basis) from its oil and gas properties and compares these estimates to the carrying values of thethose properties. The estimatedEstimated future cash flows used to test those properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable reserves utilizing
and assumptions generally consistent with the assumptions utilizedused by the Company's managementCompany for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil adjusted accordingly for basis differentials, future operating costs and inflation, some of which are interdependent.inflation. Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount raterates and other assumptions that marketplace participants would use in their estimates of fair value. value estimates.
There were no indicators of impairment identified during 2017. Due toin 2020.
During the declines in commodity prices during 2016 and 2015,fourth quarter of 2019, there were indicationsindicators that the carrying values of certain of the Company’sCompany's properties may be impaired due to depressed natural gas prices and changes in the Company's development strategy, including the Company's contemplation of a potential asset divestiture of certain of its non-strategic exploration and production assets. As a result of the 2019 impairment evaluation, the Company recorded total impairment of $1,124.4 million, of which $1,035.7 million was associated with the Company's non-strategic assets located in the Ohio Utica and $88.7 million was associated with the Company's Pennsylvania and West Virginia Utica assets. The impairment was recorded as a reduction to the assets' carrying values to their estimated fair values of approximately $839.4 million with respect to the Company's Ohio Utica assets and approximately $26.8 million with respect to the Company's Pennsylvania and West Virginia Utica assets. The fair value of the impaired assets, as determined at December 31, 2019, was based on significant inputs that are not observable in the market and, as such, are considered a Level 3 fair value measurement. See Note 4 for a description of the fair value hierarchy. Key assumptions included in the calculation of the fair value included the following: (i) reserves, including risk adjustments for probable reserves; (ii) future commodity prices; (iii) to the extent available, market-based indicators of fair value, including estimated proceeds that could be realized upon a potential disposition; (iv) production rates based on the Company's experience with similar properties; (v) future operating and development costs; (vi) inflation and (vii) a market-based weighted average cost of capital.
During 2018, there were indicators that the carrying values of certain of the Company's oil and gas producing properties may be impaired. The Company performed an undiscounted cash flow analysis for said propertiesimpaired due to the Company's intention to sell its Huron and determined that no impairment existed during 2016. During 2015,Permian assets before the undiscounted cash flows attributed to certain assets indicated thatend of their carrying amounts were not expected to be fully recovered.useful lives. As a result of
the 2018 impairment evaluation, the Company performed a discounted cash flow analysisrecorded impairment of $2.4 billion associated with the Company's Huron and determined the fair valuePermian assets. See Note 7 for discussion of the assets using an income approach based upon estimates of future production levels, commodity prices, operating costsHuron and discount rates. The future production levels, future commodity prices, which were derived from the five-year forward price curve as adjusted for basis differentials and transportation costs, future operating costs, future inflation factors, as well as the assumed market participant discount rate, were considered to be significant unobservable inputs in the Company's calculation of fair value. As a result, valuation of the impaired assets was considered to be a Level 3 fair value measurement. For the year ended December 31, 2015, EQT Production recognized pre-tax impairment charges on proved oil and gas properties of $98.6 million, which is included in impairment of long-lived assets in the Statements of Consolidated Operations. The 2015 impairment included a charge of $94.3 million to record the proved properties in the Permian Basin of Texas at a fair value of $44.8 million and a charge of $4.3 million to record the proved properties in the Utica Shale of Ohio at a fair value of $5.7 million. After this charge to the Permian assets the carrying valuedivestitures.
Impairment and Expiration of Permian properties as of December 31, 2015 was approximately $345 million, including approximately $300 million of undeveloped properties. The 2015 impairment on proved properties in the Permian Basin of Texas was due to a decline in commodity prices. The 2015 impairment in the Utica Shale of Ohio was a result of insufficient recovery of hydrocarbons to support continued development, along with the decline in commodity prices.
Leases. Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis.basis at least annually. Indicators of potential impairment include changes brought about bydue to economic factors, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. If itthe Company does not intend to drill on the property prior to expiration of the lease or does not have the intent and ability to extend, renew, trade or sell the lease prior to expiration, impairment expense is determined thatrecorded. Expense for lease expirations where the properties willlease was not yield proved reserves,previously impaired is recorded as the related costs are expensed in the period in which that determination is made. For the year ended December 31, 2017, EQT Production recorded no unproved property impairment.lease expires. For the years ended December 31, 20162020, 2019 and 2015, EQT Production2018, the Company recorded unproved property impairments of $6.9$306.7 million, $556.4 million and $19.7$279.7 million, respectively, which are included in impairment of long-lived assets in the Statements of Consolidated Operations.for lease impairments and expirations. The Company's unproved property impairment in 2016 and 2015 related to leases not yet expired that would not be drilled prior to expiration. In addition, unproved lease expirations prior to drilling of $7.6 million, $8.7 million and $37.4 million are included in exploration expense of EQT Production for the years ended December 31, 2017, 2016 and 2015, respectively. Unproved properties had a net book value of $5,016.3approximately $2,292 million and $1,698.8$3,322 million at December 31, 20172020 and 2016,2019, respectively.
During each of the years 2017 and 2015, the Company drilled one exploratory dry hole within its non-core acreage and the related expenditures have been included within exploration expense in the Statements of Consolidated Operations as of December 31, 2017 and 2015, respectively. There were no capitalized exploratory wells costs at December 31, 2017. At December 31, 2016, the Company had $5.1 million of capitalized exploratory well costs.
Gathering and transmission property, plant and equipment is carried at cost. Depreciation is calculated using the straight-line method based on estimated service lives. The Company's property consists largely of gathering and transmission systems (20 - 65 year estimated service life), buildings (35 year estimated service life), office equipment (3 - 7 year estimated service life), vehicles (5 year estimated service life), and computer and telecommunications equipment and systems (3 - 7 year estimated service life). Water pipelines, pumping stations and impoundment facilities are carried at cost and depreciated on a straight line basis over a useful life of 10 to 15 years.
Maintenance projects that do not increase the overall life of the related assets are expensed. When maintenance materially increases the life or value of the underlying asset, the cost is capitalized.
When events or changes in circumstances indicate that the carrying amount of any long-lived asset other than proved and unproved oil and gas properties may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Company records an impairment loss equal to the difference between the carrying value and fair value of the assets. No impairment of any long-lived asset other than proved and unproved oil and gas properties was recorded in 2017. During the year ended December 31, 2016, the Company
recorded an impairment of long-lived assets of approximately $59.7 million related to certain gathering assets sold to EQM in October 2016. Using the income approach and Level 3 fair value inputs, these gathering assets were written down to fair value. The impairment was triggered by a reduction in estimated future cash flows caused by the low commodity price environment and resulting reduced producer drilling activity and related throughput. During the year ended December 31, 2015, the Company recorded an impairment of long-lived assets of approximately $4.2 million related to an asset that will not be utilized in operations.
Goodwill: Goodwill. Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business.
Goodwill is evaluatedtested for impairment at the Company's single reporting unit level on at least annually,an annual basis or wheneverif events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Company may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of aits reporting unit may not exceedis below its carrying amount. Tovalue. The Company considers market capitalization and other valuation techniques, as applicable, when estimating fair value for goodwill impairment testing purposes.
In connection with the extent that such indicators exist, a two-step2018 annual goodwill impairment test, is completed. the Company identified several qualitative factors that are generally considered when assessing goodwill for impairment, including the steep decline in the Company's stock price through the quarter ended December 31, 2018, the weak market performance of the Company's peers for the same period, the Company's excess capital spend compared to the capital budget announced in October 2018, the recent operational volume curtailments and the Company's strategy to slow the cadence of its future drilling operations.
The Company performed the first step comparesof the goodwill impairment test for its single reporting unit as of November 30, 2018. The Company used its market capitalization plus a control premium to estimate fair value for its single reporting unit. Estimated market capitalization was calculated by multiplying the Company's 30-day weighted average stock price and the number of aoutstanding common stock of the Company (EQT common stock) as of November 30, 2018. The reporting unit tounit's estimated fair value was significantly less than its carrying value. Ifvalue and, as such, all of the carrying amountgoodwill was impaired. This impairment charge was classified as a component of a reporting unit exceeds its fair value,operating expenses.
Contract Asset. See Note 5 for discussion of the second step compares the implied fairCompany's contract asset.
The carrying value of the goodwillCompany's contract asset is reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of a reporting unitthe Company's contract asset has occurred, the Company compares the estimated undiscounted future cash flows to itsthe carrying value. Estimated future cash flows are based on the estimated volumes and the in-service date of the Mountain Valley Pipeline. If the contract asset's carrying amount exceeds the estimated future undiscounted cash flows, it is written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates.
During 2020, the Company identified indicators that the carrying value of the goodwillcontract asset may not be fully recoverable due to further delays of the timing of completion of the Mountain Valley Pipeline as well as changes to the regulatory landscape. The Company performed the first step of the impairment test and determined the estimated expected undiscounted future cash flows exceeded the carrying value of the contract asset, indicating the contract asset was not impaired. The estimated undiscounted future cash flows were based on significant inputs that are not observable in the market and, as such, are considered a reporting unit exceeds its impliedLevel 3 fair value the difference is recognized as an impairment charge. The Company usesmeasurement. See Note 4 for a combinationdescription of the income and market approaches to estimate the fair value hierarchy. Key assumptions in the calculation of estimated undiscounted future cash flows included estimated production volumes subject to the Consolidated GGA (defined in Note 5to the Consolidated Financial Statements) and a reporting unit.probability-weighted estimate of the in-service date of the Mountain Valley Pipeline.
Investment in Equitrans Midstream Corporation. As of December 31, 2020, the Company owned approximately 25 million shares of common stock of Equitrans Midstream Corporation (Equitrans Midstream). The Company evaluated goodwilldoes not have the ability to exercise significant influence and does not have a controlling financial interest in Equitrans Midstream or any of its subsidiaries. As such, its investment in Equitrans Midstream is accounted for impairmentas an investment in equity securities and recorded at December 31, 2017fair value in the Consolidated Balance Sheets. The fair value is calculated by multiplying the closing stock price of Equitrans Midstream's common stock by the number of shares of Equitrans Midstream's common stock owned by the Company. Changes
in fair value are recorded in loss on investment in Equitrans Midstream Corporation in the Statements of Consolidated Operations. See Note 4 for a description of the fair value hierarchy. Dividends received on the investment in Equitrans Midstream are recorded in dividend and determined there was no indicatorother income in the Statements of impairment.Consolidated Operations. See Note 5 and Note 8.
Intangible Assets: IntangibleAssets. The Company's intangible assets arewere recorded under the acquisition method of accounting at their estimated fair values at the acquisition date. Fair value is calculated as the present valuedate of estimated future cash flows using a risk-adjusted discount rate.Rice Energy Inc. (Rice Energy). The Company’sCompany's intangible assets arewere composed of customer relationships and non-compete agreements with former Rice Energy Inc. (Rice) executives. The customer relationships acquired have a useful life of approximately 15 years and the non-competitionnon-compete agreements havehad a useful life of 3 years. The Company calculates amortization of intangible assets using theon a straight-line methodbasis over the estimated useful life of the intangible assets. Amortization expense recorded in the consolidated statements of operations for the year ended December 31, 2017 was $10.9 million. The estimated annual amortization expense over the next five years is as follows: 2018 $82.9 million, 2019 $82.9 million, 2020 $77.5 million, 2021 $41.5 million and 2022 $41.5 million.
IntangibleCompany's intangible assets netwere fully amortized as of December 31, 2017 are detailed below.2020.
|
| | | |
| (in thousands) | December 31, 2017 |
| Customer relationships | $ | 623,200 |
|
| Less: accumulated amortization for customer relationships | (5,540 | ) |
| Non-compete agreements | 124,100 |
|
| Less: accumulated amortization for non-compete agreements | (5,400 | ) |
| Intangible assets, net | $ | 736,360 |
|
Sales and Retirements Policies: No gain or loss is recognized on the partial sale of proved developed oil and gas reserves unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds.
Regulatory Accounting: The regulated operations of EQM Transmission include interstate pipeline and storage operations subject to regulation by the FERC. EQM Gathering's regulated operations include certain FERC-regulated gathering operations. The application of regulatory accounting allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Statements of Consolidated Operations for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the Statements of Consolidated Operations in the period in which the same amounts are reflected in rates.
The following table presentssummarizes the total regulated net revenues and operating expenses included inCompany's intangible assets.
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| (Thousands) |
| Non-compete agreements | $ | 108,689 | | | $ | 124,100 | |
| Less: Accumulated amortization | 108,689 | | | 82,683 | |
| Less: Impairment of intangible assets (a) | 0 | | | 15,411 | |
| Intangible assets, net | $ | 0 | | | $ | 26,006 | |
(a)In 2019 the operationsCompany recognized impairment of EQM Transmission and EQM Gathering: its intangible assets associated with non-compete agreements for former Rice Energy executives who are now employees of the Company.
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Net revenues | $ | 390,883 |
| | $ | 347,320 |
| | $ | 309,984 |
|
| Operating expenses | $ | 151,510 |
| | $ | 118,611 |
| | $ | 109,954 |
|
Other Current Liabilities.The following table presentssummarizes the regulated net property, plant and equipment included in EQM Transmission and EQM Gathering:Company's other current liabilities.
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (Thousands) |
| Property, plant & equipment | $ | 1,787,656 |
| | $ | 1,675,433 |
|
| Accumulated depreciation and amortization | (278,756 | ) | | (234,336 | ) |
| Net property, plant & equipment | $ | 1,508,900 |
| | $ | 1,441,097 |
|
| | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| | (Thousands) |
| Accrued interest payable | $ | 91,953 | | | $ | 36,590 | |
| Current portion of long-term capacity contracts | 50,504 | | | 34,000 | |
| Taxes other than income | 44,619 | | | 57,850 | |
| Incentive compensation | 33,601 | | | 18,573 | |
| Current portion of operating lease liabilities | 25,004 | | | 29,036 | |
| Income tax payable | 23,909 | | | 0 | |
| Severance accrual | 2,536 | | | 11,769 | |
| Other accrued liabilities | 29,785 | | | 32,746 | |
| Total other current liabilities | $ | 301,911 | | | $ | 220,564 | |
Regulatory assets associated with deferred taxes of $17.7 million and $20.3 million as of December 31, 2017 and 2016, respectively, are included in other assets in the Consolidated Balance Sheets and primarily represent deferred income taxes recoverable through future rates related to a historical deferred tax position and the equity component of allowance for funds used during construction (AFUDC). The Company expects to recover the amortization of the deferred tax position ratably over the corresponding life of the underlying assets that created the difference. The deferred tax regulatory asset associated with AFUDC represents the offset to the deferred taxes associated with the equity component of AFUDC of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes will be collected through rates over the depreciable lives of the long-lived assets to which they relate.
Regulatory liabilities associated with deferred taxes of $11.3 million as of December 31, 2017 are included in the Consolidated Balance Sheets and represent excess deferred taxes associated with public utility property as a result of the federal income tax rate reduction from 35% to 21% (as discussed in Note 11). Following the normalization provisions of the Internal Revenue Code (IRC), this regulatory liability is amortized on a straight-line basis over the estimated remaining life of the related assets.
Derivative Instruments: Derivatives are held as part of a formally documented risk management program. The Company’s use of derivative instruments is implemented under a set of policies approved by the Company’s Hedge and Financial Risk Committee (HFRC) and reviewed by the Audit Committee of the Company's Board of Directors. The HFRC is composed of the president and chief executive officer, the chief financial officer and other officers of the Company.
In regards to commodity price risk, the financial instruments currently utilized by the Company are primarily fixed price swap agreements, collar agreements and option agreements. The Company engages in basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and interest rate swaps to hedge exposure to interest rate fluctuations on potential debt issuances. The Company also uses a limited number of other contractual agreements in implementing its commodity hedging strategy. The Company has an insignificant number of natural gas derivative instruments for trading purposes.
Effective December 31, 2014, the Company elected to de-designate all derivative commodity instruments that were designated and qualified as cash flow hedges. Any changes in fair value of derivative instruments are recognized net within operating revenues in the Statements of Consolidated Operations. If a cash flow hedge was terminated or de-designated as a hedge before the settlement date of the hedged item, the amount of deferred gain or loss within accumulated other comprehensive income (OCI) recorded up to that date remained deferred, provided that the forecasted transaction remained probable of occurring. Subsequent changes in fair value of a de-designated derivative instrument are recorded in earnings. The amount recorded in accumulated OCI is related to instruments that were previously designated as cash flow hedges. Since December 31, 2014, the Company has not designated any new derivative instruments as cash flow hedges.
AFUDC: Carrying costs for the construction of certain regulated assets are capitalized by the Company and amortized over the related assets’ estimated useful lives. The capitalized amount includes interest cost (debt portion) and a designated cost of equity (equity portion) for financing the construction of these assets which are subject to regulation by the FERC.
The debt portion of AFUDC is calculated based on the average cost of debt and is included as a reduction of interest expense in the Statements of Consolidated Operations. AFUDC interest costs capitalized were $0.8 million, $2.4 million and $1.6 million for the years ended December 31, 2017, 2016 and 2015, respectively.
The equity portion of AFUDC is calculated using the most recent equity rate of return approved by the applicable regulator. Equity amounts capitalized are included in other income in the Statements of Consolidated Operations. The AFUDC equity amounts capitalized were $5.1 million, $19.4 million and $6.3 million for the years ended December 31, 2017, 2016 and 2015, respectively.
Other Current Liabilities: Other current liabilities as of December 31, 2017 and 2016 are detailed below.
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Thousands) |
| Mountain Valley Pipeline, LLC capital call | $ | 105,734 |
| | $ | 11,471 |
|
| Incentive compensation | 91,363 |
| | 100,762 |
|
| Taxes other than income | 78,749 |
| | 56,874 |
|
| Accrued interest payable | 52,993 |
| | 39,593 |
|
| Severance accrual | 41,474 |
| | 338 |
|
| All other accrued liabilities | 60,212 |
| | 27,681 |
|
| Total other current liabilities | $ | 430,525 |
| | $ | 236,719 |
|
Revenue Recognition: Revenue is recognized for production and gathering activities when deliveries of natural gas, NGLs and crude oil occur and title to the products is transferred to the buyer. Revenues from natural gas transmission and storage activities are recognized in the period the service is provided. Reservation revenues on firm contracted capacity are recognized over the contract period based on the contracted volume regardless of the amount of natural gas that is transported. The Company reports revenue from all energy trading contracts net in the Statements of Consolidated Operations, regardless of whether the contracts are physically or financially settled. Contracts which result in physical delivery of a commodity expected to be used or sold by the Company in the normal course of business are considered normal purchases and sales and are not subject to derivative accounting. Revenues from these contracts are recognized at contract value when delivered and are reported in operating revenues. The Company reports all gains and losses on its derivative commodity instruments net as operating revenues on its Statements of Consolidated Operations. The Company uses the gross method to account for overhead cost reimbursements from joint operating partners. During periods in which rates are subject to refund as a result of a pending rate case, the Company records revenue at the rates which are pending approval but reserves these revenues to the level of previously approved rates until the final settlement of the rate case. See Recently Issued Accounting Standards within this footnote for further information.
Investments in Consolidated Affiliates: In January 2015, the Company formed EQT GP Holdings, LP (EQGP) to own the Company's partnership interests in EQM. On May 15, 2015, EQGP completed an initial public offering (IPO) of 26,450,000 common units representing limited partner interests in EQGP, which represented 9.9% of EQGP's outstanding limited partner interests. The Company retained 239,715,000 common units, which represented a 90.1% limited partner interest, and the entire non-economic general partner interest, in EQGP. As of December 31, 2017, EQGP owned 21,811,643 EQM common units, representing a 26.6% limited partner interest in EQM; 1,443,015 EQM general partner units, representing a 1.8% general partner interest in EQM; and all of EQM's incentive distribution rights (IDRs).
Following the Rice Merger, the Company owned 100% of the outstanding limited liability company interests in Rice Midstream Management, LLC (the RMP General Partner), the general partner of RMP, and 100% of the general partner and limited partner interests in Rice Midstream GP Holdings, LP (RMGP). As of December 31, 2017, the RMP General Partner owned the entire non-economic general partner interest in RMP, and RMGP owned 3,623 RMP common units and 28,753,623 subordinated units, representing a 28.1% limited partner interest in RMP, and all of RMP's IDRs. On February 15, 2018, the RMP subordinated units issued to RMGP converted into RMP common units on a one-for-one basis.
Each of EQGP, EQM and RMP are consolidated in the Company's consolidated financial statements, and the Company reports the noncontrolling interests of the public limited partners in its financial statements. See Notes 3, 4 and5.
Strike Force Midstream Holdings LLC (Strike Force Holdings), an indirect wholly owned subsidiary of the Company, owns a 75% limited liability interest in Strike Force Midstream LLC (Strike Force Midstream). The Company consolidates Strike Force
Midstream and records the noncontrolling interest of the minority owners in its financial statements. Strike Force Holdings results are reported in the results of the EQT Production business segment in Note 13.
Investment in Unconsolidated Entity: Investments in a company in which the Company has the ability to exert significant influence over operating and financial policies (generally 20% to 50% ownership), but which the Company does not control, are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The Company evaluates its investment in the unconsolidated entities for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value that is other than temporary, the Company compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss. See Note 12.
Unamortized Debt Discount and Issuance Expense: Expense. Discounts and expenses incurred with the issuance of debt are amortized over the termlife of the debt. These amounts are presented as a reduction of Senior Notes onsenior notes in the accompanying Consolidated Balance Sheets. See Note 15.10.
Transportation and Processing: Third-party costs incurred to gather, process and transport gas produced by EQT Production to market sales points are recorded as transportation and processing costs in the Statements of Consolidated Operations. The Company markets some transportation for resale. These costs, which are not incurred to transport gas produced by EQT Production, are reflected as a deduction from pipeline, water and net marketing services revenues.
Income Taxes:Taxes. The Company files a consolidated U.S. federal income tax return and utilizesuses the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable net of amounts refunded or estimated to be refunded for the current year and the change in deferred taxes exclusive of amounts recorded in OCI.other comprehensive income (OCI). Any refinements to prior years’year taxes made in the current year due to subsequentnew information are reflected as adjustments in the current period. Separate income taxes are calculated for income from continuing operations, income from discontinued operations and items charged or credited directly to shareholders’shareholders' equity.
Deferred income tax assets and liabilities are determined based onarise from temporary differences between the financial reporting and tax bases of the Company's assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that somea portion or all of the deferred tax asset will not be realized.
In accounting for uncertainty in income taxes of a tax position taken or expected to be taken in a tax return, the Company utilizesuses a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination,
including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit.position. If it is more likely than not that a tax position will be sustained, then the Company must measuremeasures and recognizes the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that ishas a greater than 50% likelylikelihood of being realized upon ultimate settlement. The Company recognizes accrued interest and penalties accrued related to unrecognized tax benefits in income tax expense. See Note 9.
ProvisionInsurance. The Company maintains insurance to cover traditional insurable risks such as general liability, workers compensation, auto liability, environmental liability, property damage, business interruption and other risks. These policies may be subject to deductible or retention amounts, coverage limitations and exclusions. The Company was previously self-insured for Doubtful Accounts: Judgmentcertain material losses related to general liability and certain other casualty coverages, such as workers compensation, auto liability and environmental liability. However, the Company is requiredno longer self-insured with respect to assessany material losses related to general liability, workers compensation or environmental liability arising on or after November 12, 2020, or for losses related to auto liability arising on or after November 12, 2019. The recorded reserves represent estimates of the ultimate realizationcost of claims incurred as of the Company’s accounts receivable, including assessing the probability of collection and the creditworthiness of certain customers.balance sheet date. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense in the Statements of Consolidated Operations. The reserves areestimated based on analyses of historical experience, currentdata and expected economic trendsactuarial estimates and specific information about customer accounts.
Earnings Per Share (EPS): Basic EPS are computed by dividing net income attributable to EQTnot discounted. The liabilities are reviewed by the weighted average numberCompany quarterly and by independent actuaries annually to ensure appropriateness. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of common shares outstanding during the period, without considering any dilutive items. Diluted EPS are computed by dividing net income attributable to EQT by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities ariseclaims, differ from the assumed conversion of outstanding stock options and other share-based awards. See Note 17.estimates.
Asset Retirement Obligations: Obligations. The Company accrues a liability for legal asset retirement obligations based on an estimate of the timingamount and amounttiming of settlement. For oil and gas wells, the fair value of the Company’sCompany's plugging and abandonment obligations is required to be recorded at the time the obligations areobligation is incurred, which is typically at the time the wells arewell is spud. Upon initial
recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value through charges to depreciation and depletion and amortization, and theexpense. The initial capitalized costs are depleted over the useful lives of the related assets.
EQT Production’sThe Company's asset retirement obligations related to the abandonment of oil and gas producing facilities include reclaiming drilling sites, plugging wells and dismantling related structures. Estimates are based on historical experience inof plugging and abandoning wells and reclaiming or disposing of other assets as well as theand estimated remaining lives of the wells and assets. RMP Water's asset retirement obligations relate to dismantling, reclaiming or disposing of water services assets.
The Company is under no legal or contractual obligation to restore or dismantle its gathering systems and transmission and storage system upon abandonment. Additionally, the Company operates and maintains its gathering systems and transmission and storage system and it intends to do so as long as supply and demand for natural gas exists, which the Company expects for the foreseeable future. Therefore, the Company does not have any asset retirement obligations related to its gathering systems and transmission and storage system as of December 31, 2017 and 2016.
The following table presents a reconciliation of the beginning and ending carrying amounts of the Company’sCompany's asset retirement obligations which are included in other liabilities and credits in the Consolidated Balance Sheets.
| | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| | (Thousands) |
| Balance at January 1 | $ | 461,821 | | | $ | 287,805 | |
| Accretion expense | 22,506 | | | 13,733 | |
| Liabilities incurred | 10,293 | | | 8,985 | |
| Liabilities settled | (4,030) | | | (3,569) | |
| Liabilities assumed in acquisitions | 45,825 | | | 0 | |
| Liabilities removed due to divestitures | (54,836) | | | (5,535) | |
| Change in estimates | 41,978 | | | 160,402 | |
| Balance at December 31 | $ | 523,557 | | | $ | 461,821 | |
The Company does not have any assets that are legally restricted for purposes of settling these obligations.
|
| | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 |
| | (Thousands) |
| Asset retirement obligation as of beginning of period | $ | 243,600 |
| | $ | 168,142 |
|
| Accretion expense | 13,679 |
| | 9,696 |
|
| Liabilities incurred | 19,678 |
| | 2,943 |
|
| Liabilities settled | (3,838 | ) | | (1,484 | ) |
| Liabilities assumed in Rice Merger | 50,941 |
| | — |
|
| Change in estimates | 128,610 |
| | 64,303 |
|
| Asset retirement obligation as of end of period | $ | 452,670 |
| | $ | 243,600 |
|
During 20172020 and 2016,2019, the Company had changes in estimates for the plugging of horizontal and conventional and horizontal wells that were related primarily related to pad reclamation and increased cost assumptions of complyingfor the Company's compliance with existing regulatory requirements whichthat were derived, in part, based onfrom recent plugging experience and actual costs incurred. The Company operates in several states that have implemented enhancedexpanded requirements that resulted in the Company's use of additional materials during the plugging process, which has increased the estimated cost for plugging horizontal and conventional wells.
Revenue Recognition. For information on revenue recognition from contracts with customers and gains and losses on derivative commodity instruments see Notes 2 and 3, respectively.
Transportation and Processing. Costs incurred to plug these wells over recent years.
Self-Insurance: The Company is self-insured for certain losses related to workers’ compensationgather, process and maintains a self-insured retention for general liability, automobile liability, environmental liability and other casualty coverage. The Company maintains stop loss coverage with third-party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers’ compensation. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewedtransport gas produced by management quarterly and by independent actuaries annually to ensure that they are appropriate. While the Company believes these estimatesto market sales points are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims, differ from estimates.
Noncontrolling Interests: Noncontrolling interests represent third-party equity ownershiprecorded as transportation and processing costs in EQGP, EQM, RMP and Strike Force Midstream and are presented as a component of equity in the Consolidated Balance Sheets. In the Statements of Consolidated Operations, noncontrolling interests reflectOperations. The Company markets some transportation for resale. These costs, which are not incurred to transport gas produced by the allocationCompany, are reflected as a deduction from net marketing services and other revenues.
Share-based Compensation. See Notes 3, 4, and 5 for further discussion of noncontrolling interests related to EQGP, EQM and RMP, respectively, and Note 13 for furthera discussion of the noncontrolling interestCompany's share-based compensation plans.
Provision for Doubtful Accounts. Reserves for uncollectible accounts are recorded in Strike Force Midstream.selling, general and administrative expense in the Statements of Consolidated Operations. Judgment is required to assess the ultimate realization of the Company's accounts receivable. Reserves are based on historical experience, current and expected economic trends and specific information about customer accounts, such as the customer's creditworthiness.
Pension and Other Post-Retirement Benefit Plans: Operating Expenses. The following table summarizes the Company's other operating expenses.
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | | 2019 | | 2018 |
| (Thousands) |
| Changes in legal reserves, including settlements | $ | 11,350 | | | $ | 82,395 | | | $ | 51,677 | |
| Transactions | 11,739 | | | 0 | | | 26,331 | |
| Reorganization, including severance and contract terminations | 5,448 | | | 97,702 | | | 0 | |
| Proxy | 0 | | | 19,343 | | | 0 | |
| Total other operating expenses | $ | 28,537 | | | $ | 199,440 | | | $ | 78,008 | |
Other Postretirement Benefits Plan. The Company as sponsor of the EQT Corporation Retirement Plansponsors a plan for Employees (Retirement Plan), a defined benefit pension plan, terminated the Retirement Plan effective December 31, 2014. On March 2, 2016, the Internal Revenue Service (IRS) issued a favorable determination letter for the termination of the Retirement Plan. On June 28, 2016, thepostretirement benefits plan. The Company purchased annuities from, and transferred the Retirement Plan assets and liabilities to, American General Life Insurance Company. As a result, during 2016, the Company reclassified the actuarial losses remaining in accumulated other comprehensive loss of approximately $9.4 million to earnings and approximately $5.1 million to a regulatory
asset that will be amortized for rate recovery purposes over a period of 16 years. In connection with the purchase of annuities, the Company made a cash payment of approximately $5.4 million to fully fund the Retirement Plan upon liquidation during the second quarter of 2016.
Currently, the Company recognizesrecognized expense for on-going post-retirement benefits other than pensions, a portion of which expense is subject to recovery in the approved rates of EQM's rate-regulated business.
Expense recognized by the Company related to its defined contribution plan totaled $16.6of $6.5 million, $8.9 million and $17.3 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Earnings Per Share (EPS). Basic EPS is computed by dividing net income attributable to EQT by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to EQT by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards as well as the conversion premium on the Convertible Notes. Purchases of treasury shares are calculated using the average share price of EQT common stock during the period.
In periods when the Company reports a net loss, all options, restricted stock, performance awards and stock appreciation rights are excluded from the calculation of diluted weighted average shares outstanding because of their anti-dilutive effect on loss per share. As a result, for the years ended December 31, 2020, 2019 and 2018, all securities, totaling 6,778,383, 3,035,247 and 2,211,122, respectively, were excluded from potentially dilutive securities because of their anti-dilutive effect on EPS.
As discussed in 2017, $16.0 million in 2016Note 10, the Company issued the Convertible Notes during the second quarter of 2020 and, $15.7 million in 2015.
Supplemental Cash Flow Information: Non-cash investing activitiesupon conversion of the Convertible Notes, intends to use a combined settlement approach to satisfy its settlement obligation under the Convertible Notes. As such, there is no adjustment to the diluted EPS numerator for the cash-settled portion of the instrument. For the year ended December 31, 20172020, the conversion premium of 6,666,670 shares was excluded from potentially dilutive securities because of its anti-dilutive effect on loss per share.
Supplemental Cash Flow Information. The following table summarizes net cash paid (received) for interest and income taxes and non-cash activity included $143.6 million for asset retirement cost additions, $94.3 million for the increase in the MVP investment as a resultConsolidated Statements of the capital contributions payable, $4.4 million for changes in accrualsCash Flows.
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | | 2019 | | 2018 |
| (Thousands) |
| Cash paid (received) during the year for: | | | | | |
| Interest, net of amount capitalized | $ | 195,681 | | | $ | 198,562 | | | $ | 260,959 | |
| Income taxes, net | (448,906) | | | (1,710) | | | (3,675) | |
| | | | | |
| Non-cash activity during the period for: | | | | | |
| Increase in asset retirement costs and obligations | $ | 52,271 | | | $ | 169,387 | | | $ | 34,602 | |
| Increase in right-of-use assets and lease liabilities, net | 18,877 | | | 113,350 | | | 0 | |
| Capitalization of non-cash equity share-based compensation | 3,142 | | | 0 | | | 4,314 | |
| Measurement period adjustments for prior period acquisitions | 0 | | | 0 | | | 14,377 | |
Table of property, plant and equipment, $10.0 million of net liabilities assumed in 2017 acquisitions, $(14.3) million for measurement period adjustments for 2016 acquisitions and $9.0 million in capitalized non-cash stock based compensation. See discussion of equity issued in consideration for the Rice Merger in Note 2. Non-cash investing activities for the year ended December 31, 2016 included $87.6 million of net liabilities assumed in acquisitions, $(27.7) million for changes in accruals of property, plant and equipment, $66.2 million for asset retirement cost additions, $11.5 million for the increase in the MVP investment as a result of the capital contributions payable and $16.6 million in capitalized non-cash stock based compensation. Non-cash investing activities for the year ended December 31, 2015 included $(114.8) million for changes in accruals of property, plant and equipment, $7.0 million for asset retirement cost additions, and $25.2 million in capitalized non-cash stock based compensation.Contents
Recently Issued Accounting Standards: Standards
In May 2014,June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers - Deferral of the Effective Date which approved a one year deferral of ASU No. 2014-09 for annual reporting periods beginning after December 15, 2017. During the third quarter of 2017, the Company substantially completed its detailed review of the impact of the standard on each of its contracts. The Company adopted the ASUs using the modified retrospective method of adoption on January 1, 2018 and did not require an adjustment to the opening balance of equity. The Company does not expect the standard to have a significant impact on its results of operations, liquidity or financial position in 2018. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers including disaggregation of revenue and remaining performance obligations. The Company implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and generate the disclosures required under the new standard in the first quarter of 2018.
In January 2016, the FASB issued ASU No. 2016-01, 2016-13, Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. The changes primarily affect the accounting for equity investments, financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. This standard will eliminate the cost method of accounting for equity investments. The ASU will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period, with early adoption of certain provisions permitted. The Company will adopt this standard in the first quarter of 2018 and does not expect that the adoption of the standard will have a material impact on its financial statements and related disclosures.
In February 2016, the FASB issued ASU No. 2016-02, Leases. The primary effect of adopting the new standard on leases will be to record assets and obligations for contracts currently recognized as operating leases. Lessees and lessors must apply a modified retrospective transition approach. The ASU will be effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period, with early adoption permitted. The Company has completed a high level identification of agreements covered by this standard and will continue to evaluate the impact this standard will have on its financial statements, internal controls and related disclosures.
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation: Improvements to Employee Share-Based Payment Accounting. This ASU is part of the FASB initiative to reduce complexity in accounting standards. The areas for simplification in this ASU involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted this standard in the first quarter of 2017 with no significant impact on its financial statements or related disclosures. The Company chose to adopt the classification of excess tax benefits on the statement of cash flows prospectively. Therefore, prior periods have not been adjusted.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-CreditInstruments – Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entityentities to reflect itstheir current estimate of all expected credit losses. The amendments affectamendment affects loans, debt securities, trade receivables, net investments in leases, off balanceoff-balance sheet credit exposures, reinsurance receivables and any other financial assets not excluded from theits scope that have thea contractual right to receive cash. TheThis ASU will beis effective for annual reporting periodsfiscal years beginning after December 15, 2019, including interim periods within that reporting period.those fiscal years. The Company is currently evaluating the impactadopted this standard will haveASU on January 1, 2020 with no changes to its methodology, financial statements and relatedor disclosures.
In August 2016,July 2018, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments2018-07, Improvements to Nonemployee Share-Based Payment Accounting. This ASU addressesexpands the presentation and classificationscope of eight specific cash flow issues. The amendments in theTopic 718, Compensation – Share Compensation, to include share-based payment transactions where a grantor acquires goods or services from a nonemployee. This ASU will beis effective for public business entities for annual reporting periodsfiscal years beginning after December 15, 2017,2018, including interim periods within that reporting period, withthose fiscal years, and early adoption is permitted. The Company anticipatesadopted this standard will not have a material impactASU on January 1, 2020 with no changes to its methodology, financial statements and relatedor disclosures.
In January 2017,August 2018, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying2018-13, Fair Value Measurement, Changes to the Definition of a Business.Disclosure Requirements for Fair Value Measurement. This ASU clarifiesmodifies the definition of a businesshierarchy associated with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The ASU will be effective for public business entities for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company anticipates this standard will not have a material impact on its financial statementsLevel 1, 2 and related disclosures.
In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test of Goodwill Impairment (Topic 350). This ASU simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied3 fair value of goodwill (Step 2 ofmeasurements and the current goodwill impairment test). Instead, a company would record an impairment charge based on the excess of a reporting unit’s carrying value over its fair value (measured in Step 1 of the current goodwill impairment test).related disclosure requirements. This updateASU is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. Entities will apply the standard’s provisions prospectively. The Company is currently evaluating the impact thatadopted this guidance will haveASU on January 1, 2020 with no changes to its consolidatedmethodology, financial statements but currently believes it will not have a material quantitative effect on the financial statements, unless an impairment charge is necessary.or disclosures.
In March 2017,August 2018, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost2018-15, Intangibles – Goodwill and Net Periodic Postretirement Benefit CostOther – Internal-Use Software: Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. This ASU provides additional guidance on the presentation of net benefit costaccounting for implementation costs incurred by a customer in the income statement and on the components eligible for capitalization in assets. Thea cloud computing arrangement that is a service contract. This ASU will beis effective for public business entities for annual reporting periodsfiscal years beginning after December 15, 2017,2019, including interim periods within that reporting period, withthose fiscal years, and early adoption is permitted. The Company anticipatesadopted this standard willASU prospectively on January 1, 2020, at which point onward applicable costs were capitalized to the Consolidated Balance Sheet rather than expensed to selling, general and administrative expense in the Statement of Consolidated Operations. For the year ended December 31, 2020, such capitalized costs were approximately $9 million.
In December 2019, the FASB issued ASU 2019-12, Income Taxes: Simplifying the Accounting for Income Taxes. This ASU simplifies accounting for income taxes by eliminating certain exceptions to ASC 740, Income Taxes, related to the general approach for intraperiod tax allocation, methodology for calculating income taxes in an interim period and recognition of deferred taxes when there are investment ownership changes. In addition, this ASU simplifies aspects of accounting for franchise taxes and interim period effects of enacted changes in tax laws or rates and provides clarification on accounting for transactions that result in a step up in the tax basis of goodwill and allocation of consolidated income tax expense to separate financial statements of entities not subject to income tax. This ASU is effective for fiscal years beginning after December 15, 2020, including interim periods within those fiscal years, and early adoption is permitted. The Company plans to adopt this ASU in the first quarter of 2021 and does not expect this adoption to have a material impact on its financial statements and related disclosures.
In May 2017,August 2020, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification2020-06, Debt with Conversion and Other Options and Derivatives and Hedging: Accounting for Convertible Instruments and Contracts in an Entity's Own Equity. This ASU provides guidance regarding which changes tosimplifies accounting for convertible instruments by removing certain separation models for convertible instruments. For convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in substantial premiums accounted for as paid-in capital, the terms or conditionsconvertible instrument's embedded conversion features are no longer separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost. This ASU also amends the impact of a share-based payment award require an entity to apply modification accounting. Theconvertible instruments on the calculation of diluted EPS and adds several new disclosure requirements. This ASU will beis effective for annual reporting periodsfiscal years beginning after December 15, 2017,2021, including interim periods within that reporting period, with early adoption permitted.those fiscal years. The Company plans to adopt this ASU on January 1, 2022 using the full retrospective method of adoption. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures.
Subsequent Events:Events. The Company has evaluated subsequent events through the date of the financial statement issuance.
2. Rice Merger
On November 13, 2017,2.Revenue from Contracts with Customers
Under the Company's natural gas, natural gas liquids (NGLs) and oil sales contracts, the Company completed its previously announced acquisitiongenerally considers the delivery of Rice Energy Inc. (Rice) pursuanteach unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. These contracts typically require payment within 25 days of the Agreement and Planend of Merger, dated asthe calendar month in which the commodity is delivered. A significant number of June 19, 2017 (as amended,these contracts contain variable consideration because the Merger Agreement), by and amongpayment terms refer to market prices at future delivery dates. In these situations, the Company Rice andhas not identified a wholly owned indirect subsidiary of the Company (RE Merger Sub). Pursuant tostandalone selling price because the terms of the Merger Agreement,variable payments relate specifically to the Company's efforts to satisfy the performance obligations. Other contracts, such as fixed price contracts or contracts with a fixed differential to New York Mercantile Exchange (NYMEX) or index prices, contain fixed consideration. The fixed consideration is allocated to each performance obligation on November 13, 2017, RE Merger Sub merged with and into Rice (the Rice Merger) with Rice continuing asa relative standalone selling price basis, which requires judgment from management. For these contracts, the surviving corporation and a wholly owned indirect subsidiaryCompany generally concludes that the fixed price or fixed differentials in the contracts are representative of the Company. Immediately afterstandalone selling price.
Based on management's judgment, the effectiveperformance obligations for the sale of natural gas, NGLs and oil are satisfied at a point in time because the customer obtains control and legal title of the Rice Merger (the Effective Time), Rice merged with and into another wholly owned indirect subsidiary ofasset when the Company.
At the Effective Time, each share of the common stock, par value $0.01 per share, of Rice (the Rice Common Stock) issued and outstanding immediately priornatural gas, NGLs or oil is delivered to the Effective Time was converted into the right to receive 0.37 (the Exchange Ratio)designated sales point.
The sales of a share of the common stock, no par value, of the Company (Company Common Stock)natural gas, NGLs and $5.30 in cash (collectively, the Merger Consideration). The aggregate Merger Consideration consisted of approximately 91 million shares of Company Common Stock and approximately $1.6 billion in cash (net of cash acquired and inclusive of amounts payable to employees of Rice who did not continue with the Company following the Effective Time). See Note 18 for further details.
In connection with the closing of the Rice Merger, the Company paid an aggregate of $555.5 million, includedoil presented in the cash paid for the Merger Consideration of approximately $1.6 billion (net of cash acquired and inclusive of amounts payable to employees of Rice who did not continue with the Company following the Effective Time), to affiliates of EIG Global Energy Partners (collectively, the EIG Funds) to redeem the EIG Funds' respective interests in Rice Midstream Holdings LLC (Rice Midstream Holdings) and RMGP (the EIG Redemptions). Following the EIG Redemptions, each of Rice Midstream Holdings and RMGP are indirect wholly owned subsidiaries of the Company.
In connection with the closing of the Rice Merger, the Company repaid the $321.0 million of outstanding principal under Rice Energy Operating LLC's revolving credit facility and the $187.5 million of outstanding principal under Rice Midstream Holdings' revolving credit facility, together with interest and fees of $1.4 million and $0.3 million, respectively, and the credit agreements were terminated.
Also in connection with the Rice Merger, Rice redeemed and canceled all of its outstanding 6.25% Senior Notes due 2022 (the Rice 2022 Notes) and 7.25% Senior Notes due 2023 (the Rice 2023 Notes) on November 13, 2017. The Company made aggregate payments of $1.4 billion in connection with the note redemptions, including make whole call premiums of $42.2 million and $21.6 million for the Rice 2022 Notes and the Rice 2023 Notes, respectively, and $13.4 million of required interest payments on the Rice 2023 Notes.
The Company acquired a total of approximately 270,000 net acres through the Rice Merger, which includes approximately 205,000 net Marcellus acres, as well as approximately 65,000 net Utica acres in Ohio. The Company also acquired Upper Devonian and Utica drilling rights held in Pennsylvania.
The Company also acquired the interests in RMP disclosed in Note 1.
During the nine months ended September 30, 2017, the Company expensed $8.0 million in debt issuance costs related to a bridge financing commitment to support the Rice Merger. The Company also recorded $237.3 million in acquisition-related expenses related to the Rice Merger during the year ended December 31, 2017. The Rice Merger acquisition related expenses included $75.3 million for stock based compensation and $66.1 million for other compensation arrangements and are included in the StatementStatements of Consolidated Operations Acquisition Costs line.represent the Company's share of revenues net of royalties and exclude revenue interests owned by others. When selling natural gas, NGLs and oil on behalf of royalty or working interest owners, the Company is acting as an agent and, thus, reports the revenue on a net basis.
Rice’s operating revenues represented approximately 10%For contracts with customers where the Company's performance obligations had been satisfied and an unconditional right to consideration existed as of the Company’s consolidated operating revenuesbalance sheet date, the Company recorded amounts due from contracts with customers of $394.1 million and Rice's income before income taxes represented approximately 24%$384.0 million in accounts receivable in the Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively.
The table below provides disaggregated information on the Company’s consolidated income before income taxes, bothCompany's revenues. Certain contracts that provide for the year ended December 31, 2017.release of capacity that is not used to transport the Company's produced volumes are outside the scope of ASU 2014-09, Revenue from Contracts with Customers. The costs of, and recoveries on, such capacity are reported in net marketing services and other in the Statements of Consolidated Operations. Derivative contracts are also outside the scope of ASU 2014-09.
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | | 2019 | | 2018 |
| (Thousands) |
| Revenues from contracts with customers: | | | | | |
| Natural gas sales | $ | 2,459,854 | | | $ | 3,559,809 | | | $ | 4,217,684 | |
| NGLs sales | 169,871 | | | 197,985 | | | 442,010 | |
| Oil sales | 20,574 | | | 33,620 | | | 35,825 | |
| Net marketing services and other | 0 | | | 0 | | | 13,865 | |
| Total revenues from contracts with customers | 2,650,299 | | | 3,791,414 | | | 4,709,384 | |
| | | | | |
| Other sources of revenue: | | | | | |
| Net marketing services and other | 8,330 | | | 8,436 | | | 27,075 | |
| Gain (loss) on derivatives not designated as hedges | 400,214 | | | 616,634 | | | (178,591) | |
| Total operating revenues | $ | 3,058,843 | | | $ | 4,416,484 | | | $ | 4,557,868 | |
Allocation of Purchase Price
The Rice Merger has been accounted for as a business combination, using the acquisition method. The following table summarizes the preliminary purchase price and the preliminary estimated fair values of assets and liabilities assumed as of November 13, 2017, with any excess of the purchase price over the estimated fair value of the identified net assets acquired recorded as goodwill. Approximately, $549.2 million and $1,449.5 million of goodwill has been allocated to EQT Production and RMP Gathering, respectively. Goodwill primarily relates to the value of RMP which cannot be assigned to other assets recognized under GAAP as substantially all of RMP's revenues are from affiliates, deferred tax liabilities arising from differences between the purchasetransaction price allocated to Rice’s assets and liabilities basedthe Company's remaining performance obligations on fair value and the tax basis of these assets and liabilities that
carried over to the Company in the Rice Merger and the Company’s ability to control the Rice acquired assets and recognize synergies. Certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, title defect analysis and final appraisals of assets acquired and liabilities assumed and the finalization of certain income tax computations. The Company expects to complete the purchase price allocation once the Company has received all of the necessary information, at which time the value of the assets and liabilities will be revised as appropriate.
|
| | | |
| (in thousands) | Preliminary Purchase Price Allocation |
| Consideration Given: | |
| Equity consideration | $ | 5,943,289 |
|
| Cash consideration | 1,299,407 |
|
| Buyout of preferred equity in Rice Midstream Holdings | 429,708 |
|
| Buyout of Common Units in RMGP | 125,828 |
|
| Settlement of pre-existing relationships | (14,699 | ) |
| Total consideration | 7,783,533 |
|
| | |
| Fair value of liabilities assumed: | |
| Current liabilities | 566,774 |
|
| Long-term debt | 2,151,656 |
|
| Deferred income taxes | 1,106,000 |
|
| Other long term liabilities | 67,533 |
|
| Amount attributable to liabilities assumed | 3,891,963 |
|
| | |
| Fair value of assets acquired: | |
| Cash | 294,671 |
|
| Accounts receivable | 337,007 |
|
| Current assets | 109,465 |
|
| Net property, plant and equipment | 9,903,938 |
|
| Intangible assets | 747,300 |
|
| Noncontrolling interests | (1,715,611 | ) |
| Amount attributable to assets acquired | 9,676,770 |
|
| Goodwill as of December 31, 2017 | $ | 1,998,726 |
|
The fair values of natural gas and oil properties are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using valuation techniques that convert future cash flows into a single discounted amount. Significant inputs to the valuation of natural gas and oil properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital. These inputs required significant judgments and estimates by management, are still under review, and may be subject to change. These inputs have a significant impact on the valuation of oil and gas properties and future changes may occur. The fair value of undeveloped property was determined based upon a market approach of comparable transactions using Level 3 inputs.
The estimated fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations, is estimated using the cost approach. Significant unobservable inputs in the estimate of fair value include management’s assumptions about the replacement costs for similar assets, the relative age of the acquired assets and any potential economic or functional obsolescence associatedcontracts with the acquired assets. As a result, the estimated fair value of the midstream facilities and equipment represents a level 3 fair value measurement.
The non-controlling interest in the acquired business is comprised of the limited partner units in RMP which were not acquired by EQT as well as the non-controlling interest in Strike Force Midstream. The RMP limited partner units are actively traded on the New York Stock Exchage, and were valued based on observable market prices as of the transaction date and therefore
represent a level 1 fair value measurement. The non-controlling interest in Strike Force Midstream was calculated based on the enterprise value of Strike Force Midstream and the percentage ownership not acquired by EQT. Significant unobservable inputs in the estimate of the enterprise value of Strike Force Midstream include the future revenue estimates and future cost assumptions. As a result, the non-controlling interest in Strike Force Midstream represents a level 3 fair value measurement.
As part of the preliminary purchase price allocation, the Company identified intangible assets for customer relationships with third party customers and non-compete agreements with certain former Rice executives. The fair value of the identified intangible assets was determined using the income approach which requires a forecast of the expected future cash flows generated and an estimated market-based weighted average cost of capital. Significant unobservable inputs in the determination of fair value include future production levels, future revenues estimates, future cost assumptions, the estimated probability that former executives would compete in the absence of such non-compete agreements and estimated customer retention rates. As a result, the estimated fair value of the identified intangible assets represents a level 3 fair value measurement. Differences between the preliminary purchase price allocation and the final purchase price allocation may change the amount of intangible assets and goodwill ultimately recognized in conjunction with the Rice Merger.
In conjunction with the Rice Merger, the Company has carryover tax basis of $422.5 million of tax deductible goodwill.
Post-Acquisition Operating Results
Subsequent to the completion of the Rice Merger, the acquired entities contributed the following to the Company’s consolidated operating results for the period from November 13, 2017 through December 31, 2017.
|
| | | |
| (in thousands) | |
| Revenue attributable to EQT | $ | 323,414 |
|
| Net income attributable to noncontrolling interests | $ | 16,644 |
|
| Net income attributable to EQT | $ | 529,743 |
|
Net income attributable to EQT includes a tax benefit of $410.9 million for the revaluation of Rice’s net deferred tax liabilities as a result of the Tax Reform Legislation discussed in Note 11.
Unaudited Pro Forma Information
The following unaudited pro forma combined financial information presents the Company’s results as though the Rice Merger had been completed at January 1, 2016. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Rice Merger taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results.
|
| | | | | | | |
| | For the year ended December 31, |
| (in thousands, except per share data) (unaudited) | 2017 | | 2016 |
| Pro forma operating revenues | $ | 4,809,757 |
| | $ | 2,288,605 |
|
| Pro forma net income (loss) | $ | 2,197,041 |
| | $ | (528,786 | ) |
| Pro forma net income attributable to noncontrolling interests | $ | (444,248 | ) | | $ | (401,149 | ) |
| Pro forma net income (loss) attributable to EQT | $ | 1,752,793 |
| | $ | (929,935 | ) |
| Pro forma income (loss) per share (basic) | $ | 6.30 |
| | $ | (3.59 | ) |
| Pro forma income (loss) per share (diluted) | $ | 6.29 |
| | $ | (3.59 | ) |
3. EQT GP Holdings, LP
At December 31, 2017 and 2016, EQGP owned the following EQM partnership interests, which represent EQGP's only cash-generating assets: 21,811,643 EQM common units, representing a 26.6% limited partner interest in EQM; 1,443,015 EQM general partner units, representing a 1.8% general partner interest in EQM; and all of EQM's IDRs, which entitle EQGP to receive 48.0% of all incremental cash distributed in a quarter after $0.5250 has been distributed in respect of each common unit and general partner unit of EQM for that quarter. The Company is the ultimate parent company of EQGP and EQM.
The Company received net proceeds from EQGP's 2015 IPO of approximately $674.0 million after deducting the underwriters' discount of approximately $37.5 million and structuring fees of approximately $2.7 million. EQGP did not receive any of the proceeds from, or incur any expenses in connection with, EQGP's IPO. In connection with the EQGP IPO, the Company recorded a $320.4 million gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of $512.9 million and an increase to deferred tax liability of $192.5 million.
The Company continues to consolidate the results of EQGP, but records an income tax provision only as to its ownership percentage. The Company records the noncontrolling interest of the EQGP and EQM public limited partners (i.e., the EQGP limited partner interests not owned by the Company and the EQM limited partner interests not owned by EQGP) in its financial statements.
On January 18, 2018, the Board of Directors of EQGP's general partner declared a cash distribution to EQGP's unitholders for the fourth quarter of 2017 of $0.244 per common unit, or approximately $64.9 million. The cash distribution will be paid on February 23, 2018 to unitholders of record, including the Company, at the close of business on February 2, 2018.
4.EQT Midstream Partners, LP
In January 2012, the Company formed EQM to own, operate, acquire and develop midstream assets in the Appalachian Basin. EQM provides midstream services to the Company and other third parties.
EQM Equity Offerings: The following table summarizes EQM's public offerings of its common units during the three years ended December 31, 2017. |
| | | | | | | | | | | | | | | | | | |
| | | Common Units Issued | | GP Units Issued | | Price Per Unit | | Net Proceeds | | Underwriters' Discount and Other Offering Expenses |
| | | (Thousands, except unit and per unit amounts) |
March 2015 equity offering (a) | | 9,487,500 |
| | 25,255 |
| | $ | 76.00 |
| | $ | 696,582 |
| | $ | 24,468 |
|
$750 million At the Market (ATM) Program in 2015 (b) | | 1,162,475 |
| | — |
| | 74.92 |
| | 85,483 |
| | 1,610 |
|
November 2015 equity offering (c) | | 5,650,000 |
| | — |
| | 71.80 |
| | 399,937 |
| | 5,733 |
|
$750 million ATM Program in 2016 (d) | | 2,949,309 |
| | — |
| | $ | 74.42 |
| | $ | 217,102 |
| | $ | 2,381 |
|
| |
(a) | The underwriters exercised their option to purchase additional common units. EQM Midstream Services, LLC, the general partner of EQM (the EQM General Partner), purchased 25,255 EQM general partner units for approximately $1.9 million to maintain its then 2.0% general partner ownership percentage. In connection with the offering, the Company recorded a $122.3 million gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of $195.8 million and an increase to deferred tax liability of $73.5 million. EQM used the proceeds from the offering to fund a portion of the purchase price for the NWV Gathering Transaction discussed below. |
| |
(b) | In 2015, EQM entered into an equity distribution agreement that established an "At the Market" (ATM) common unit offering program, pursuant to which a group of managers, acting as EQM's sales agents, may sell EQM common units having an aggregate offering price of up to $750 million (the $750 million ATM Program). The price per unit represents an average price for all issuances under the $750 million ATM Program in 2015. The underwriters' discount and other offering expenses in the table include commissions of approximately $0.9 million and other offering expenses of approximately $0.7 million. In connection with the offerings, the Company recorded a $12.4 million gain to additional |
paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of $19.8 million and an increase to deferred tax liability of $7.4 million. EQM used the net proceeds from the sales for general partnership purposes.
| |
(c) | EQM used the net proceeds for general partnership purposes and to repay amounts outstanding under EQM's revolving credit facility. In connection with the offering, the Company recorded a $52.1 million gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of $83.5 million and an increase to deferred tax liability of $31.3 million. |
| |
(d) | The price per unit represents an average price for all issuances under the $750 million ATM Program in 2016. The underwriters' discount and offering expenses in the table include commissions of approximately $2.2 million. In connection with these sales, the Company recorded a $24.9 million gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of $39.9 million and an increase to deferred tax liability of $15.0 million. EQM used the net proceeds for general partnership purposes. |
Transactions between EQT and EQM: In the ordinary course of business, EQT engages in transactions with EQM including, but not limited to, gas gathering and transmission agreements.
On March 17, 2015, the Company contributed the Northern West Virginia Marcellus gathering system to EQM in exchange for totalfixed consideration of $925.7 million (the NWV Gathering Transaction). On April 15, 2015, the Company transferred a preferred interest (the Preferred Interest) in EQT Energy Supply, LLC, an indirect subsidiary of the Company, to EQM in exchange for total consideration of $124.3 million. EQT Energy Supply, LLC generates revenue from services provided to a local distribution company.
On March 30, 2015, the Company assigned 100% of the membership interest in MVP Holdco, LLC (MVP Holdco), which at the time was its indirect wholly owned subsidiary, to EQM and received $54.2 million, which represented EQM's reimbursement to the Company for 100% of the capital contributions made by the Company to Mountain Valley Pipeline, LLC (MVP Joint Venture) as of March 30, 2015. As of February 15, 2018, EQM owned a 45.5% interest (the MVP Interest) in the MVP Joint Venture. The MVP Joint Venture plans to construct the Mountain Valley Pipeline (MVP), an estimated 300-mile natural gas interstate pipeline spanning from northern West Virginia to southern Virginia. The MVP Joint Venture has secured a total of 2.0 Bcf per day of 20-year firm capacity commitments, including a 1.29 Bcf per day firm capacity commitment by the Company. On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for the project. In early 2018, the MVP Joint Venture received limited notice to proceed with certain construction activities from the FERC. The MVP Joint Venture plans to commence construction in the first quarter of 2018. The pipeline is targeted to be placed in-service during the fourth quarter of 2018. See Note 12.
On October 13, 2016, EQM acquired from the Company (i) 100% of the outstanding limited liability company interests of Allegheny Valley Connector, LLC and Rager Mountain Storage Company LLC and (ii) certain gathering assets located in southwestern Pennsylvania and northern West Virginia (collectively, the October 2016 Sale). The closing of the October 2016 Sale occurred on October 13, 2016 and was effective as of October 1, 2016. The aggregate consideration paid by EQM to the Company in connection with the October 2016 Sale was $275 million, which was funded with borrowings under EQM's revolving credit facility. Concurrent with the October 2016 Sale, the operating agreement of EQT Energy Supply, LLC was amended to include mandatory redemption of the Preferred Interest at the end of the preference period, which is expected to be December 31, 2034. As a result of this amendment, EQM's investment in EQT Energy Supply, LLC converted to a note receivable for accounting purposes effective October 1, 2016. The Company recorded an impairment of long-lived assets of approximately $59.7 million related to certain gathering assets sold to EQM in the October 2016 Sale. See Note 1.
The expenses for which EQM reimburses EQT and its subsidiaries related to corporate and general and administrative services may not necessarily reflect the actual expenses that EQM would incur on a stand-alone basis. EQM is unable to estimate what the costs would have been with an unrelated third party.
EQM has a $500 million, 364-day, uncommitted revolving loan agreement with EQT that matures on October 24, 2018 and will automatically renew for successive 364-day periods unless EQT delivers a non-renewal notice at least 60 days prior to the then current maturity date (the 364-Day Facility). EQM may terminate the 364-Day Facility at any time by repaying in full the unpaid principal amount of all loans together with interest thereon. The 364-Day Facility is available for general partnership purposes and does not contain any covenants other than the obligation to pay accrued interest on outstanding borrowings. Interest will accrue on any outstanding borrowings at an interest rate equal to the rate then applicable to similar loans under EQM's $1 billion revolving credit facility, or a successor revolving credit facility, less the sum of (i) the then applicable commitment fee under EQM's $1 billion revolving credit facility and (ii) 10 basis points. EQM had no borrowings outstanding under the 364-Day Facility as of December 31, 2017. During2020. Amounts shown exclude contracts that qualified for the year endedexception to the relative standalone selling price method as of December 31, 2017, the maximum amount2020.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2022 | | 2023 | | | | Total |
| (Thousands) |
| Natural gas sales | $ | 178,100 | | | $ | 8,158 | | | $ | 6,794 | | | | | $ | 193,052 | |
For the year ended December 31, 2017, interest was incurred at a weighted average annual interest rate of approximately 2.2%. There were no amounts outstanding at any time on the 364-Day Facility in 2016.
In November 2016, EQM issued 4.125% Senior Notes due 2026 (the 4.125% Senior Notes) in the aggregate principal amount of $500 million. Net proceeds from the offering of $491.4 million were used to repay the outstanding borrowings under EQM’s revolving credit facility and for general partnership purposes. The 4.125% Senior Notes contain covenants that limit EQM’s ability to, among other things, incur certain liens securing indebtedness, engage in certain sale and leaseback transactions, and enter into certain consolidations, mergers, conveyances, transfers or leases of all or substantially all of EQM’s assets.
See Note 14 for discussion of EQM's $1.0 billion credit facility.
On January 18, 2018, the Board of Directors of EQM’s general partner declared a cash distribution to EQM’s unitholders for the fourth quarter of 2017 of $1.025 per common unit. The cash distribution was paid on February 14, 2018 to unitholders of record, including EQGP, at the close of business on February 2, 2018. Cash distributions by EQM to EQGP were approximately $65.7 million consisting of: $22.4 million in respect of its limited partner interest, $2.2 million in respect of its general partner interest and $41.1 million in respect of its IDRs in EQM.
5.Rice Midstream Partners LP
RMP owns, operates and develops midstream assets in the Appalachian Basin. RMP's assets consist of gathering pipelines and compressor stations, as well as water handling and treatment facilities. RMP provides gathering and water services to the Company and third parties. The Company is the ultimate parent company of RMP, and the Company records the noncontrolling interest of the RMP public limited partners in its financial statements.
On January 18, 2018, the Board of Directors of the RMP General Partner declared a cash distribution to RMP’s unitholders for the fourth quarter of 2017 of $0.2917 per common and subordinated unit. The cash distribution was paid on February 14, 2018 to unitholders of record at the close of business on February 2, 2018. Cash distributions by RMP to RMGP were approximately $11.4 million, consisting of $8.4 million in respect of its limited partner interest and $3.0 million in respect of its IDRs in RMP.
On the closing date of the Rice Merger, in connection with the completion of the Rice Merger, RMP, EQT and various other EQT subsidiaries entered into an Amended and Restated Omnibus Agreement, pursuant to which RMP is obligated to reimburse EQT for the provision of general and administrative services for its benefit, for direct expenses incurred by EQT on RMP’s behalf, for expenses allocated to it as a result of being a public entity and for an allocated portion of the compensation expense of the executive officers and other employees of EQT and its affiliates who perform centralized corporate and general and administrative services on substantially the same terms as the original omnibus agreement.
See Note 14 for discussion of RMP's $850 million credit facility.
6.Financial Information by Business Segment
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2017 | EQT Production | | EQM Gathering | | EQM Transmission | | RMP Gathering | | RMP Water | | Intersegment Eliminations | | EQT Corporation |
| | (Thousands) |
| Revenues: | | | | | | | | | | | | | |
| Sales of natural gas, oil and NGLs | $ | 2,651,318 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,651,318 |
|
| Pipeline, water and net marketing services | 64,998 |
| | 454,536 |
| | 379,560 |
| | 30,614 |
| | 13,605 |
| | (606,637 | ) | | 336,676 |
|
| Gain on derivatives not designated as hedges | 390,021 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 390,021 |
|
| Total operating revenues | $ | 3,106,337 |
| | $ | 454,536 |
| | $ | 379,560 |
| | $ | 30,614 |
| | $ | 13,605 |
| | $ | (606,637 | ) | | $ | 3,378,015 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2016 | EQT Production | | EQM Gathering | | EQM Transmission | | Intersegment Eliminations | | EQT Corporation |
| | (Thousands) |
| Revenues: | | | | | | | | | |
| Sales of natural gas, oil and NGLs | $ | 1,594,997 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,594,997 |
|
| Pipeline and net marketing services | 41,048 |
| | 397,494 |
| | 338,120 |
| | (514,320 | ) | | 262,342 |
|
| Loss on derivatives not designated as hedges | (248,991 | ) | | — |
| | — |
| | — |
| | (248,991 | ) |
| Total operating revenues | $ | 1,387,054 |
| | $ | 397,494 |
| | $ | 338,120 |
| | $ | (514,320 | ) | | $ | 1,608,348 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2015 | EQT Production | | EQM Gathering | | EQM Transmission | | Intersegment Eliminations | | EQT Corporation |
| | (Thousands) |
| Revenues: | | | | | | | | | |
| Sales of natural gas, oil and NGLs | $ | 1,690,360 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,690,360 |
|
| Pipeline and net marketing services | 55,542 |
| | 335,105 |
| | 297,831 |
| | (424,838 | ) | | 263,640 |
|
| Gain on derivatives not designated as hedges | 385,762 |
| | — |
| | — |
| | — |
| | 385,762 |
|
| Total operating revenues | $ | 2,131,664 |
| | $ | 335,105 |
| | $ | 297,831 |
| | $ | (424,838 | ) | | $ | 2,339,762 |
|
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | |
| | (Thousands) | | |
|
| Operating income (loss): | | |
| | |
| | |
|
| EQT Production (a) | | $ | 589,716 |
| | $ | (719,731 | ) | | $ | 132,008 |
|
| EQM Gathering | | 333,563 |
| | 289,027 |
| | 243,257 |
|
| EQM Transmission | | 247,145 |
| | 237,922 |
| | 207,779 |
|
| RMP Gathering (b) | | 21,800 |
| | — |
| | — |
|
| RMP Water (b) | | 4,145 |
| | — |
| | — |
|
| Unallocated expenses (c) | | (263,388 | ) | | (85,518 | ) | | (19,905 | ) |
| Total operating income (loss) | | $ | 932,981 |
| | $ | (278,300 | ) | | $ | 563,139 |
|
| | | | | | | |
| Reconciliation of operating income (loss) to net income (loss): |
| Total operating income (loss) | | $ | 932,981 |
| | $ | (278,300 | ) | | $ | 563,139 |
|
| Other income | | 24,955 |
| | 31,693 |
| | 9,953 |
|
| Loss on debt extinguishment | | 12,641 |
| | — |
| | — |
|
| Interest expense | | 202,772 |
| | 147,920 |
| | 146,531 |
|
| Income tax (benefit) expense | | (1,115,619 | ) | | (263,464 | ) | | 104,675 |
|
| Net income (loss) | | $ | 1,858,142 |
| | $ | (131,063 | ) | | $ | 321,886 |
|
| |
(a) | For the year ended December 31, 2017, the operating income for EQT Production includes the results of operations for the production operations and retained midstream operations acquired in the Rice Merger for the period of November 13, 2017 through December 31, 2017. See Note 2 for a discussion of the Rice Merger. Gains on sales / exchanges of assets of $8.0 million are included in EQT Production operating income for 2016. See Note 9. Impairment of long-lived assets of $6.9 million and $122.5 million are included in EQT Production operating income for 2016 and 2015, respectively. See Note 1 for a discussion of impairment of long-lived assets. |
| |
(b) | Operating income for RMP Gathering and RMP Water, both acquired in the Rice Merger, includes the results of operations for the period of November 13, 2017 through December 31, 2017. See Note 2 for a discussion of the Rice Merger. |
| |
(c) | Unallocated expenses generally include incentive compensation expense and administrative costs. In addition, 2017 includes $237.3 million of Rice Merger related expenses and 2016 includes a $59.7 million impairment on gathering assets prior to the sale to EQM. |
|
| | | | | | | | | | | | |
| | | As of December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Segment assets: | | |
| | |
| | |
| EQT Production | | $ | 22,711,854 |
| | $ | 10,923,824 |
| | $ | 9,905,344 |
|
| EQM Gathering | | 1,411,857 |
| | 1,225,686 |
| | 1,019,004 |
|
| EQM Transmission | | 1,462,881 |
| | 1,399,201 |
| | 1,169,517 |
|
| RMP Gathering | | 2,720,305 |
| | — |
| | — |
|
| RMP Water | | 185,079 |
| | — |
| | — |
|
| Total operating segments | | 28,491,976 |
| | 13,548,711 |
| | 12,093,865 |
|
| Headquarters assets, including cash and short-term investments | | 1,030,628 |
| | 1,924,211 |
| | 1,882,307 |
|
| Total assets | | $ | 29,522,604 |
| | $ | 15,472,922 |
| | $ | 13,976,172 |
|
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | | | (Thousands) | | |
| Depreciation, depletion and amortization: (d) | | |
| | |
| | |
|
| EQT Production (e) | | $ | 982,103 |
| | $ | 859,018 |
| | $ | 765,298 |
|
| EQM Gathering | | 38,796 |
| | 30,422 |
| | 24,360 |
|
| EQM Transmission (g) | | 58,689 |
| | 32,269 |
| | 25,535 |
|
| RMP Gathering (f) | | 3,965 |
| | — |
| | — |
|
| RMP Water (f) | | 3,515 |
| | — |
| | — |
|
| Other (g) | | (9,509 | ) | | 6,211 |
| | 4,023 |
|
| Total | | $ | 1,077,559 |
| | $ | 927,920 |
| | $ | 819,216 |
|
| | | | | | | |
| Expenditures for segment assets: (h) | | |
| | |
| | |
|
| EQT Production (e) (i) | | $ | 2,430,094 |
| | $ | 2,073,907 |
| | $ | 1,893,750 |
|
| EQM Gathering | | 196,871 |
| | 295,315 |
| | 225,537 |
|
| EQM Transmission | | 111,102 |
| | 292,049 |
| | 203,706 |
|
| RMP Gathering (f) (j) | | 28,320 |
| | — |
| | — |
|
| RMP Water (f) (j) | | 6,233 |
| | — |
| | — |
|
| Other | | 6,080 |
| | 7,002 |
| | 21,421 |
|
| Total | | $ | 2,778,700 |
| | $ | 2,668,273 |
| | $ | 2,344,414 |
|
(d) Excludes amortization of intangible assets.
| |
(e) | For the year ended December 31, 2017, depreciation, depletion and amortization expense and expenditures for segment assets for EQT Production includes activity for the production operations and retained midstream operations acquired in the Rice Merger for the period of November 13, 2017 through December 31, 2017. See Note 2 for a discussion of the Rice Merger. |
| |
(f) | Depreciation, depletion and amortization expense and expenditures for segment assets for RMP Gathering and RMP Water, both acquired in the Rice Merger, includes activity for the period of November 13, 2017 through December 31, 2017. See Note 2 for a discussion of the Rice Merger. |
| |
(g) | Depreciation, depletion and amortization expense for EQM Transmission includes a non-cash charge of $10.5 million related to the revaluation of differences between the regulatory and tax bases in EQM's regulated property, plant and equipment. For purposes of consolidated reporting at EQT, the $10.5 million is recorded to income tax expense. This reclass is shown as a reduction of other depreciation, depletion and amortization expense. |
| |
(h) | Includes the capitalized portion of non-cash stock-based compensation costs, non-cash acquisitions and the impact of capital accruals. These non-cash items are excluded from capital expenditures on the statements of consolidated cash flows. The net impact of these non-cash items was $9.1 million, $76.5 million and $(89.6) million for the years ended December 31, 2017, 2016 and 2015, respectively. The impact of accrued capital expenditures includes the reversal of the prior period accrual as well as the current period estimate, both of which are non-cash items. The year ended December 31, 2017 included $10.0 million of non-cash capital expenditures related to 2017 acquisitions and $(14.3) million of measurement period adjustments for 2016 acquisitions. The year ended December 31, 2016 included $87.6 million of non-cash capital expenditures related to 2016 acquisitions. See Note 10 for discussion of the 2017 and 2016 acquisitions. Expenditures for segment assets does not include consideration for the Rice Merger. |
(i) Expenditures for segment assets in the EQT Production segment included $1,006.7 million, $1,284.0 million and $182.3 million for property acquisitions in 2017, 2016 and 2015, respectively. Included in the $1,006.7 million of property acquisitions for the year ended December 31, 2017 was $819.0 million of cash capital expenditures and $10.0 million of non-cash capital expenditures related to 2017 acquisitions and $(14.3) million of measurement period adjustments for 2016 acquisitions (see Note 10). Included in the $1,284.0 million of property acquisitions for the year ended December 31, 2016 was $1,051.2 million of capital expenditures and $87.6 million of non-cash capital expenditures for acquisitions (see Note 10).
| |
(j) | Expenditures for segment assets in the RMP Gathering and RMP Water segments included $17.1 million in cash paid by EQT for capital expenditures accrued as of the opening balance sheet date of the Rice Merger. |
7.3.Derivative Instruments
The Company’sCompany's primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the Company's operating resultsresults. The Company uses derivative commodity instruments to hedge its cash flows from sales of produced natural gas and NGLs. The overall objective of the Company primarily at EQT Production. The Company’s overall objective in itsCompany's hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.
The Company uses over the counter (OTC) derivative commodity instruments used by the Company are primarily swap, collar and option agreements. These agreements that are typically placed with financial institutions. The creditworthiness of all counterparties is regularly monitored. Swap agreements involvemay require payments to, or receiptsreceipt of payments from, counterparties based on the differential between two prices for the commodity. CollarThe Company uses these agreements requireto hedge its NYMEX and basis exposure. The Company may also use other contractual agreements when executing its commodity hedging strategy. The Company typically enters into over the counterparty to pay the Company if the index price falls below the floor pricecounter (OTC) derivative commodity instruments with financial institutions, and the Company to pay the counterparty if the index price rises above the cap price. creditworthiness of all counterparties is regularly monitored.
The Company also sells call options that requiredoes not designate any of its derivative instruments as cash flow hedges; therefore, all changes in fair value of the Company to payCompany's derivative instruments are recognized in operating revenues in the counterparty if the index price rises above the strike price. The Company engages in basis swaps to protect earnings from undue exposure to the riskStatements of geographic disparities in commodity prices and interest rate swaps to hedge exposure to interest rate fluctuations on potential debt issuances. The Company has also engaged in a limited number of swaptions and power-indexed natural gas sales and swaps that are accounted for as derivative commodity instruments.
Consolidated Operations. The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time.
The Company discontinued cash flow hedge accounting in 2014; therefore, all changes in fair value of the Company’s derivative instruments are recognized within operating revenues in the Statements of Consolidated Operations.
In prior periods, derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sales of EQT Production's produced volumes and forecasted natural gas purchases and sales were designated and qualified as cash flow hedges. As of December 31, 2017, 2016 and 2015 the forecasted transactions that were hedged as of December 31, 2014 remained probable of occurring and as such, the amounts in accumulated OCI will continue to be reported in accumulated OCI and will be reclassified into earnings in future periods when the underlying hedged transactions occur. The forecasted transactions extend through December 2018. As of December 31, 2017, and 2016, the Company deferred net gains of $4.6 million and $9.6 million, respectively, in accumulated OCI, net of tax, related to the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. The Company estimates that approximately $4.6 million of net gains on its derivative commodity instruments reflected in accumulated OCI, net of tax, as of December 31, 2017 will be recognized in earnings during the next twelve months due to the settlement of hedged transactions.
In connection with the Rice Merger, the Company assumed all outstanding derivative commodity instruments held by Rice. The assets and liabilities assumed were recognized at fair value at the closing date and subsequent changes in fair value were recognized within operating revenues in the Statements of Consolidated Operations. The derivative commodity instruments assumed were substantially similar to instruments previously held by the Company.
Contracts whichthat result in physical delivery of a commodity expected to be used or sold by the Company in the normal course of business are generally designated as normal purchases and sales and are exempt from derivative accounting. Contracts that result in the physical receipt or delivery of a commodity but are not designated or do not meet all of the criteria to qualify for the normal purchase and normal sale scope exception are subject to derivative accounting.
The Company's OTC arrangementsderivative instruments generally require settlement in cash. The Company also enters into exchange traded derivative commodity instruments that are generally settled with offsetting positions. Settlements of derivative commodity instruments are reported as a component of cash flows from operationsoperating activities in the accompanying Statements of Consolidated Cash Flows.
With respect to the derivative commodity instruments held by the Company, the Company hedged portions of expected sales of equity production and portions of its basis exposure covering approximately 2,148 Bcf1,955 billion cubic feet (Bcf) of natural gas and 8,943 Mbbls3,462 thousand barrels (Mbbl) of NGLs as of December 31, 2017,2020 and 6461,644 Bcf of natural gas and 1,095 Mbbls of NGLs as of December 31, 2016.2019. The open positions at both December 31, 20172020 and December 31, 20162019 had maturities extending through December 20222024.
Certain of the Company's OTC derivative instrument contracts provide that, if the Company's credit rating assigned by Moody's Investors Service, Inc. (Moody's) or S&P Global Ratings (S&P) is below the agreed-upon credit rating threshold (typically, below investment grade), and if the associated derivative liability exceeds the agreed-upon dollar threshold for such credit rating, the counterparty to such contract can require the Company to deposit collateral. Similarly, if such counterparty's credit rating assigned by Moody's or S&P is below the agreed-upon credit rating threshold, and if the associated derivative liability exceeds the agreed-upon dollar threshold for such credit rating, the Company can require the counterparty to deposit collateral with the Company. Such collateral can be up to 100% of the derivative liability. Investment grade refers to the quality of a company's credit as assessed by one or more credit rating agencies. To be considered investment grade, a company must be rated "Baa3" or higher by Moody's, "BBB–" or higher by S&P and "BBB–" or higher by Fitch Rating Service (Fitch). Anything below these ratings is considered non-investment grade. As of December 31, 2020, respectively.the Company's senior notes were rated "Ba3" by Moody's and "BB" by S&P.
When the net fair value of any of the Company’s swap agreementsCompany's OTC derivative instrument contracts represents a liability to the Company whichthat is in excess of the agreed-upon dollar threshold betweenfor the Company andCompany's then-applicable credit rating, the counterparty has the counterparty requiresright to require the Company to remit funds as a margin deposit forin an amount equal to the portion of the derivative liability whichthat is in excess of the dollar threshold amount. The Company records these deposits as a current asset in the Consolidated Balance Sheets. As of December 31, 2020, the aggregate fair value of all OTC derivative instruments with credit rating risk-related contingent features that were in a net liability position was $137.7 million, for which the Company deposited and recorded $21.1 million as a current asset. As of December 31, 2019, there were 0 such deposits recorded in the Consolidated Balance Sheet.
When the net fair value of any of the Company’s swap agreementsCompany's OTC derivative instrument contracts represents an asset to the Company whichthat is in excess of the agreed-upon dollar threshold betweenfor the counterparty's then-applicable credit rating, the Company andhas the counterparty, the Company requiresright to require the counterparty to remit funds as a margin depositsdeposit in an amount equal to the portion of the derivative asset whichthat is in excess of the dollar threshold amount. The Company records these deposits as a current liability for such amounts received. The Company had no such deposits in itsthe Consolidated Balance Sheets asSheets. As of December 31, 2017 or 2016.2020 and 2019, there were 0 such deposits recorded in the Consolidated Balance Sheets.
When the Company enters into exchange traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good faith deposits to guard against the risks associated with changing market conditions. The Company is required to make such deposits based on an established initial margin requirement and the net liability position, if any, of the fair value of the associated contracts. The Company records these deposits as a current asset in the Consolidated Balance Sheets. When the fair value of such contracts is in a net asset position, the broker may remit funds to the Company. The Company records these deposits as a current liability in the Consolidated Balance Sheets. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the contract. The margin requirements are subject to change at the exchanges' discretion. As of December 31, 2020 and 2019, the Company recorded $61.5 million and $12.6 million, respectively, of such deposits as a current asset in the Consolidated Balance Sheets.
Refer to Note 5 for a discussion of the derivative liability recorded in connection with the Equitrans Share Exchange (defined in Note 5).
The Company has netting agreements with financial institutions and its brokers that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The table below reflectssummarizes the impact of netting agreements and margin deposits on gross derivative assets and liabilities as of December 31, 2017 and 2016.liabilities.
| | | | | | | | | | | | | | | | | | | | | | | |
| Gross derivative instruments recorded in the
Consolidated Balance Sheet | | Derivative instruments
subject to master
netting agreements | | Margin requirements with
counterparties | | Net derivative
instruments |
| December 31, 2020 | (Thousands) |
| Asset derivative instruments at fair value | $ | 527,073 | | | $ | (328,809) | | | $ | 0 | | | $ | 198,264 | |
| Liability derivative instruments at fair value | 600,877 | | | (328,809) | | | (82,552) | | | 189,516 | |
| | | | | | | |
| December 31, 2019 | | | | | | | |
| Asset derivative instruments at fair value | $ | 812,664 | | | $ | (226,116) | | | $ | 0 | | | $ | 586,548 | |
| Liability derivative instruments at fair value | 312,696 | | | (226,116) | | | (12,606) | | | 73,974 | |
|
| | | | | | | | | | | | | | | | |
| As of December 31, 2017 | | Derivative instruments, recorded in the Consolidated Balance Sheet, gross | | Derivative instruments subject to master netting agreements | | Margin deposits remitted to counterparties | | Derivative instruments, net |
| | | (Thousands) |
| Asset derivatives: | | |
| | |
| | |
| | |
|
| Derivative instruments, at fair value | | $ | 241,952 |
| | $ | (86,856 | ) | | $ | — |
| | $ | 155,096 |
|
| Liability derivatives: | | |
| | |
| | |
| | |
|
| Derivative instruments, at fair value | | $ | 139,089 |
| | $ | (86,856 | ) | | $ | — |
| | $ | 52,233 |
|
|
| | | | | | | | | | | | | | | | |
| As of December 31, 2016 | | Derivative instruments, recorded in the Consolidated Balance Sheet, gross | | Derivative instruments subject to master netting agreements | | Margin deposits remitted to counterparties | | Derivative instruments, net |
| | | (Thousands) |
| Asset derivatives: | | |
| | |
| | |
| | |
|
| Derivative instruments, at fair value | | $ | 33,053 |
| | $ | (23,373 | ) | | $ | — |
| | $ | 9,680 |
|
| Liability derivatives: | | |
| | |
| | |
| | |
|
| Derivative instruments, at fair value | | $ | 257,943 |
| | $ | (23,373 | ) | | $ | — |
| | $ | 234,570 |
|
Certain of the Company’s derivative instrument contracts provide that if the Company’s credit ratings by Standard & Poor’s Ratings Service (S&P) or Moody’s Investors Service (Moody's) are lowered below investment grade, additional collateral must be deposited with the counterparty if the amounts outstanding on those contracts exceed certain thresholds. The additional collateral can be up to 100% of the derivative liability.Company has not executed any interest rate swaps since 2011. As of December 31, 2017, the aggregate fair value of all derivative instruments with credit risk-related contingent features2019, amounts related to historical interest rate swaps that were in a net liability position was $60.8 million, for which the Company had no collateral posted on December 31, 2017. If the Company’s credit rating by S&P or Moody’s had been downgraded below investment grade on December 31, 2017, the Company would not have been required to post any additional collateral under the agreements with the respective counterparties. The required margin on the Company's derivative instruments is subject to significant change as a result of factors other than credit rating, such as gas prices and credit thresholds set forthpreviously recorded in agreements between the hedging counterparties and the Company. Investment grade refers to the quality of the Company’s credit as assessed by one or more credit rating agencies. The Company’s senior unsecured debt was rated BBB by S&P and Baa3 by Moody’s at December 31, 2017. In order to be considered investment grade, the Company must be rated BBB- or higher by S&P and Baa3 or higher by Moody’s. Anything below these ratings is considered non-investment grade.accumulated OCI were fully reclassified into interest expense. See Note 12.
8.4.Fair Value Measurements
The Company records its financial instruments, which are principally derivative instruments, at fair value in itsthe Consolidated Balance Sheets. The Company estimates the fair value of its financial instruments using quoted market prices wherewhen available. If quoted market prices are not available, the fair value is based uponon models that use market-based parameters, as inputs, including forward curves, discount rates, volatilities and nonperformance risk.risk, as inputs. Nonperformance risk considers the effect of the Company’sCompany's credit standing on the fair value of liabilities and the effect of the counterparty’scounterparty's credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company’sCompany's or counterparty’scounterparty's credit rating and the yield ofon a risk-free instrument and credit default swaps rates where available.instrument.
The Company has categorized its assets and liabilities recorded at fair value into a three-level fair value hierarchy based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities inthat use Level 2 inputs primarily include the Company’sCompany's swap, collar and option agreements.
Exchange traded commodity swaps have Level 1 inputs. The fair value of the commodity swaps included inwith Level 2 inputs is based on standard industry income approach models that use significant observable inputs, including, but not limited to, New York Mercantile Exchange (NYMEX)NYMEX natural gas and propane
forward curves, LIBOR-based discount rates, basis forward curves and basisnatural gas liquids forward curves. The Company’s Company's
collars options, and swaptionsoptions are valued using standard industry income approach option models. The significant observable inputs utilizedused by the option pricing models include NYMEX forward curves, natural gas volatilities and LIBOR-based discount rates. The NYMEX natural gas and propane forward curves, LIBOR-based discount rates, natural gas volatilities and basis forward curves are validated to external sources at least monthly.
The followingtable below summarizes assets and liabilities were measured at fair value on a recurring basis during the applicable period:basis.
|
| | | | | | | | | | | | | | | | |
| | | | | Fair value measurements at reporting date using |
| Description | | As of December 31, 2017 | | Quoted prices in active markets for identical assets (Level 1) | | Significant other observable inputs (Level 2) | | Significant unobservable inputs (Level 3) |
| | | (Thousands) |
| Assets | | |
| | |
| | |
| | |
|
| Derivative instruments, at fair value | | $ | 241,952 |
| | $ | — |
| | $ | 241,952 |
| | $ | — |
|
| Liabilities | | |
| | |
| | |
| | |
|
| Derivative instruments, at fair value | | $ | 139,089 |
| | $ | — |
| | $ | 139,089 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | Fair value measurements at reporting date using: |
| Gross derivative instruments recorded in the Consolidated Balance Sheets | | Quoted prices in active markets
for identical assets
(Level 1) | | Significant other
observable inputs
(Level 2) | | Significant unobservable inputs
(Level 3) |
| December 31, 2020 | (Thousands) |
| Asset derivative instruments at fair value | $ | 527,073 | | | $ | 70,603 | | | $ | 456,470 | | | $ | 0 | |
| Liability derivative instruments at fair value | 600,877 | | | 93,361 | | | 507,516 | | | 0 | |
| | | | | | | |
| December 31, 2019 | | | | | | | |
| Asset derivative instruments at fair value | $ | 812,664 | | | $ | 95,041 | | | $ | 717,623 | | | $ | 0 | |
| Liability derivative instruments at fair value | 312,696 | | | 71,107 | | | 241,589 | | | 0 | |
|
| | | | | | | | | | | | | | | | |
| | | | | Fair value measurements at reporting date using |
| Description | | As of December 31, 2016 | | Quoted prices in active markets for identical assets (Level 1) | | Significant other observable inputs (Level 2) | | Significant unobservable inputs (Level 3) |
| | | (Thousands) |
| Assets | | |
| | |
| | |
| | |
|
| Trading securities | | $ | 286,396 |
| | $ | — |
| | $ | 286,396 |
| | $ | — |
|
| Derivative instruments, at fair value | | $ | 33,053 |
| | $ | — |
| | $ | 33,053 |
| | $ | — |
|
| Liabilities | | |
| | |
| | |
| | |
|
| Derivative instruments, at fair value | | $ | 257,943 |
| | $ | — |
| | $ | 257,943 |
| | $ | — |
|
The carrying values of cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value due to thetheir short-term maturitymaturities. The carrying value of the instruments.Company's investment in Equitrans Midstream approximates fair value as Equitrans Midstream is a publicly traded company. The carrying values of borrowings underon the Company's various credit facilitiesfacility and Term Loan Facility (which was fully repaid in the second quarter of 2020) approximate fair value as the interest rates are based on prevailing market rates. The Company considered all of these fair values to be Level 1 fair value measurements.
The fair values of trading securities classified as Level 2 were priced using nonbinding market prices that were corroborated by observable market data. Inputs into these valuation techniques include actual trade data, broker/dealer quotes and other similar data. During 2016, the Company reflected its initialhas an immaterial investment in trading securitiesa fund that invests in companies developing technology and operating solutions for exploration and production companies. The Company recognized a cumulative effect of accounting change related to this investment in the first quarter of 2018. The investment is valued using, as a Level 2 fairpractical expedient, the net asset value measurement. The Company did not have any investmentsprovided in trading securities as of December 31, 2017.the financial statements received from fund managers and is recorded in other assets in the Consolidated Balance Sheets.
The Company estimates the fair value of its Senior Notessenior notes using its established fair value methodology. Because not all of the Company’s SeniorCompany's senior notes are actively traded, thetheir fair value of the Senior Notes is a Level 2 fair value measurement. FairAs of December 31, 2020 and 2019, the Company's senior notes had a fair value for non-traded Senior Notesof approximately $5.2 billion and $3.9 billion, respectively, and a carrying value of approximately $4.5 billion and $3.9 billion, respectively, inclusive of any current portion. The fair value of the Company's note payable to EQM Midstream Partners, LP (EQM) is estimated using a standard industryan income approach model which utilizeswith a market-based discount rate based on market rates for debt with similar remaining timeand is a Level 3 fair value measurement. As of December 31, 2020 and 2019, the Company's note payable to maturity and credit risk. The estimatedEQM had a fair value of Senior Notes (including EQM’s Senior Notes) on the Consolidated Balance Sheets at December 31, 2017approximately $130 million and 2016 was approximately $5.7 billion$128 million, respectively, and $3.5 billion, respectively. Thea carrying value of Senior Notes (including EQM's Senior Notes) on the Consolidated Balance Sheets at December 31, 2017approximately $105 million and 2016 was approximately $5.6 billion and $3.3 billion, respectively. Refer to Notes 14 and 15$110 million, respectively, inclusive of any current portion. See Note 10 for further information regardingdiscussion of the Company's and EQM's debt as of December 31, 2017 and 2016.debt.
The Company recognizes transfers between Levels as of the actual date of the event or change in circumstances that caused the transfer. There were no transfers between Levels 1, 2 and 3 during the periods presented.
For information on the fair values, of assets related to theand impairments thereof, of proved and unproved oil and gas properties and of other long-lived assets, see Note 1. For a discussion of other fair value measurements, see Note 5 for the assets acquiredEquitrans Share Exchange, Note 6 for the Chevron Acquisition and Asset Exchange Transactions (each defined in the Rice MergerNote 6) and the assets acquired in other acquisition transactions, see Notes 1, 2, and 10.Note 7 for divestitures.
9.Sales/Exchanges of Assets5.The Equitrans Share Exchange
On December 28, 2016,February 26, 2020, the Company entered into 2 share purchase agreements (the Share Purchase Agreements) with Equitrans Midstream, pursuant to which, among other things, the Company sold to Equitrans Midstream a total of 25,299,752 shares, or 50% of its ownership, of Equitrans Midstream's common stock in exchange for approximately $52 million in cash and rate relief under certain of the Company's gathering system that primarily gathered gas for third-parties for $75.0 million. In conjunctioncontracts with this transaction,EQM, an affiliate of Equitrans Midstream (the Equitrans Share Exchange). The transactions contemplated by the Share Purchase Agreements closed on March 5, 2020 (the Share Purchase Closing Date). The rate relief was effected through the execution of the Consolidated GGA (defined herein).
On February 26, 2020, the Company realizedentered into a pre-taxgas gathering and compression agreement (the Consolidated GGA) with an affiliate of EQM, pursuant to which, among other things, EQM agreed to provide to the Company gas gathering services in the
Marcellus and Utica Shales of Pennsylvania and West Virginia, and the Company committed to an initial annual minimum volume commitment of 3.0 Bcf per day and an acreage dedication in Pennsylvania and West Virginia. The Consolidated GGA is effective through December 31, 2035 and will renew annually thereafter unless terminated by the Company or EQM. The Consolidated GGA provides for additional cash bonus payments (the Henry Hub Cash Bonus) payable by the Company to EQM during the period beginning on the first day of the quarter in which the Mountain Valley Pipeline is placed in service and ending on the earlier of 36 months thereafter or December 31, 2024. Such payments are conditioned upon the quarterly average of the NYMEX Henry Hub natural gas settlement price exceeding certain price thresholds. In addition, the Consolidated GGA provides a cash payment option that grants the Company the right to receive payments from EQM in the event that the Mountain Valley Pipeline in-service date has not occurred prior to January 1, 2022.
On the Share Purchase Closing Date, the Company recorded in the Consolidated Balance Sheet a contract asset representing the estimated fair value of the rate relief provided by the Consolidated GGA of $410 million, a derivative liability related to the Henry Hub Cash Bonus of approximately $117 million and a decrease in the Company's investment in Equitrans Midstream of approximately $158 million. The resulting gain of $8.0approximately $187 million was recorded in the Statement of Consolidated Operations. Beginning with the Mountain Valley Pipeline in-service date, the Company expects to recognize amortization of the contract asset over a period of approximately four years in a manner consistent with the expected timing of the Company's realization of the economic benefits of the rate relief provided by the Consolidated GGA. As of December 31, 2020, the derivative liability related to the Henry Hub Cash Bonus was approximately $107 million.
The fair value of the contract asset was based on significant inputs that are not observable in the market and, as such, is a Level 3 fair value measurement. Key assumptions used in the fair value calculation included an estimated production volume forecast, a market-based discount rate and a probability-weighted estimate of the in-service date of the Mountain Valley Pipeline. The fair value of the derivative liability related to the Henry Hub Cash Bonus was based on significant inputs that were interpolated from observable market data and, as such, is a Level 2 fair value measurement. See Note 4 for a description of the fair value hierarchy.
6.Acquisition and Exchange Transactions
Chevron Acquisition. In the fourth quarter of 2020, the Company acquired upstream assets and an investment in midstream gathering assets located in the Appalachian Basin from Chevron U.S.A. Inc. (Chevron) for an aggregate purchase price of $735 million, subject to certain purchase price adjustments (the Chevron Acquisition). The transaction closed on November 30, 2020 and had an effective date of July 1, 2020.
The Chevron Acquisition included approximately 335,000 net Marcellus acres, approximately 400,000 net Utica acres, approximately 550 gross wells, which are producing approximately 450 net MMcfe per day, and approximately 100 work-in-process wells at various stages in the development cycle. The Chevron Acquisition also included a 31% investment in the Laurel Mountain Midstream (LMM) gathering assets, which are operated by The Williams Companies, Inc., and 2 water systems that provide both fresh and produced water handling capabilities.
The Company does not have the power to direct the activities that most significantly impact LMM's economic performance; therefore, the Company is not the primary beneficiary and accounts for its investment in LMM as an equity method investment. The Company's pro-rata share of earnings in LMM is recorded as equity income which is included in gaindividend and other income on sale / the Statements of Consolidated Operations.
The Chevron Acquisition was accounted for as a business combination, using the acquisition method. The following table summarizes the preliminary purchase price and the preliminary estimated fair values of assets acquired and liabilities assumed as of November 30, 2020. Certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, a final title defect analysis and final appraisals of assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation during the second quarter of 2021, at which time the value of the assets acquired and liabilities assumed will be revised, if necessary.
| | | | | | | | |
| | Preliminary Purchase Price Allocation |
| | (Thousands) |
| Cash consideration (a) | | $ | 691,942 | |
| | |
| Fair value of liabilities assumed: | | |
| Accounts payable | | $ | 3,347 | |
| Other current liabilities | | 16,566 | |
| Deferred tax liability | | 939 | |
| Other liabilities and credits (b) | | 109,876 | |
| Amount attributable to liabilities assumed | | $ | 130,728 | |
| | |
| Fair value of assets acquired: | | |
| Other current assets | | $ | 5,609 | |
| Net property, plant and equipment | | 720,315 | |
| Other assets | | 96,746 | |
| Amount attributable to assets acquired | | $ | 822,670 | |
(a)The difference between cash consideration and the aggregate purchase price of $735 million represents the results of operating activities between the effective date of July 1, 2020 and the closing date of November 30, 2020 as well as amounts related to customary post-closing matters.
(b)Other liabilities and credits included liabilities due to minimum volume commitment (MVC) contracts as well as liabilities for asset retirement obligations and environmental obligations.
The fair values of the acquired natural gas and oil properties were measured using discounted cash flow valuation techniques based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include future commodity prices, projections of estimated quantities of reserves, estimated future rates of production, projected reserve recovery factors, timing and amount of future development and operating costs and a weighted average cost of capital. The fair value of the undeveloped properties were measured using the guideline transaction method based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include future development plans from a market participant perspective and value per undeveloped acre.
The fair value of the acquired investment in LMM, which is included in other assets on the Consolidated Balance Sheet, was primarily measured using discounted cash flow valuation techniques. A majority of the inputs are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include projected revenues, expenses and capital expenditures.
The fair value of the acquired MVC liabilities were measured using expected throughput and annual MVCs per associated contract calculated on a discounted basis. A majority of the inputs are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include estimated future volumes and market participant cost of debt.
2020 Asset Exchange Transactions. During 2020, the Company closed on various acreage trade agreements (collectively, the 2020 Asset Exchange Transactions), pursuant to which the Company exchanged approximately 24,400 aggregate net revenue interest acres across Greene, Allegheny, Armstrong, Westmoreland and Washington Counties, Pennsylvania; Wetzel and Marshall Counties, West Virginia; and Belmont County, Ohio for approximately 19,400 aggregate net revenue interest acres across Greene and Washington Counties, Pennsylvania; Marshall, Wetzel and Marion Counties, West Virginia; and Belmont County, Ohio. As a result of the 2020 Asset Exchange Transactions, the Company recognized a net loss of $61.6 million in impairment/loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations for the year ended December 31, 2020.
2019 Asset Exchange Transaction.During the third quarter of 2019, the Company closed on an acreage trade agreement and purchase and sale agreement with a third party (the 2019 Asset Exchange Transaction), pursuant to which the Company exchanged approximately 16,000 net revenue interest acres primarily in Wetzel and Marion Counties, West Virginia. Under the terms of the purchase and sale agreement, the Company assigned to the third party a gas gathering agreement that covers a portion of Tyler County, West Virginia and provides a firm gathering commitment, and the Company was released from its remaining obligations under that gas gathering agreement. As consideration for the third party's assumption of the Tyler County gas gathering agreement, the Company agreed to reimburse the third party for certain firm gathering costs under the gas
gathering agreement through December 2022 and assign the third party an additional approximately 3,000 net revenue interest acres in Tyler and Wetzel Counties, West Virginia.
As a result of the 2019 Asset Exchange Transaction, the Company recognized a net loss of $13.9 million in impairment/loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations for the year ended December 31, 2019. As of December 31, 2020 and 2019, the liability for the reimbursement of those certain firm gathering costs was $25.8 million and $36.8 million, respectively, and was recorded in other current and noncurrent liabilities in the Consolidated Balance Sheets.
The fair value of leases acquired and, for the 2019 Asset Exchange Transaction, the fair value of the liability for the reimbursement of certain firm gathering costs were based on inputs that are not observable in the market and, as such, are a Level 3 fair value measurement. See Note 4 for a description of the fair value hierarchy. Key assumptions used in the fair value calculations included market-based prices for comparable acreage and the net present value of expected payments due for reimbursement.
7.Divestitures
2020 Divestitures. On May 11, 2020, the Company closed a transaction to sell certain non-strategic assets located in Pennsylvania and West Virginia (the 2020 Divestiture) for an aggregate purchase price of approximately $125 million in cash, subject to customary purchase price adjustments and the Contingent Consideration defined and discussed below. The Pennsylvania assets sold included 80 Marcellus wells and approximately 33 miles of gathering lines; the West Virginia assets sold included 809 conventional wells and approximately 154 miles of gathering lines. In addition, the 2020 Divestiture relieved the Company of approximately $49 million in asset retirement obligations and other liabilities associated with the sold assets. Proceeds from the sale were used to pay down the Company's Term Loan Facility. See Note 10.
The purchase and sale agreement for the 2020 Divestiture provides for additional cash bonus payments (the Contingent Consideration) payable to the Company of up to $20 million. Such Contingent Consideration is conditioned upon the three-month average of the NYMEX Henry Hub natural gas settlement price relative to stated floor and target price thresholds beginning on August 31, 2020 and ending on November 30, 2022. The Contingent Consideration represents an embedded derivative that is recorded at fair value in the Consolidated Balance Sheets. The Contingent Consideration had 0 fair value as of May 11, 2020 and a fair value of $1.9 million as of December 31, 2020. During the year ended December 31, 2020, the Company received contingent consideration cash of $0.9 million. Changes in fair value are recorded in impairment/loss on sale/exchange of long-lived assets in the Statements of Consolidated Operations. The fair value of the Contingent Consideration is based on significant inputs that are interpolated from observable market data and, as such, is a Level 2 fair value measurement. See Note 4 for a description of the fair value hierarchy.
10.Acquisitions
In addition toAs a result of the Rice Merger discussed in Note 2,2020 Divestiture, the Company executed multiple transactions during 2016 and 2017 that resultedrecognized a net loss of $39.1 million, including the impact of the change in fair value of the Contingent Consideration, in impairment/loss on sale/exchange of long-lived assets in the Company's acquisitionStatement of approximately 304,000 net Marcellus acres, includingConsolidated Operations during the transactions listed below:year ended December 31, 2020.
On July 8, 2016,2018 Divestiture. In 2018, the Company acquired approximately 62,500 net Marcellus acressold its non-core production and 31 Marcellus wells, 24 of which were producing, from Statoil USA Onshore Properties, Inc. (the Statoil Acquisition). The net acres acquired are primarilyrelated midstream assets located in Wetzel, Tylerthe Huron play and Harrison Counties of West Virginia.
In the fourth quarter of 2016, the Company acquired approximately 42,600 net Marcellus acres and 42 Marcellus wells, 32 of which were producing at the time of the acquisition, which were being jointly developed by Trans Energy, Inc. (Trans Energy) and Republic Energy Ventures, LLC and its affiliates (collectively, Republic)Permian Basin (the 2018 Divestitures). The net acres acquired are primarily located in Wetzel, Marshall and Marion Counties of West Virginia. The acquisitions were effected through simultaneous transaction agreements that were executed on October 24, 2016 including: (i) a purchase and sale agreement between the Company and Republic; and (ii) an agreement and plan of merger among the Company, a wholly owned subsidiary of the Company (TE Merger Sub) and Trans Energy. The Republic acquisition closed on November 3, 2016 (the Republic Transaction). On October 27, 2016, the Company commenced a tender offer, through its wholly owned subsidiary, to acquire the outstanding shares of common stock of Trans Energy, a publicly traded company, at an offer price of $3.58 per share in cash. Following the tender offer on December 5, 2016, TE Merger Sub merged with and into Trans Energy, at which time Trans Energy became an indirect wholly owned subsidiary of the Company (the Trans Energy Merger).
On December 16, 2016, the Company acquired approximately 17,000 net Marcellus acres located in Washington, Westmoreland and Greene Counties of Pennsylvania, and two related Marcellus wells both of which were producing (the 2016 Pennsylvania Acquisition).
On February 1, 2017, the Company acquired approximately 14,000 net Marcellus acres located in Marion, Monongalia and Wetzel Counties of West Virginia from a third party.
On February 27, 2017, the Company acquired approximately 85,000 net Marcellus acres, including drilling rights on approximately 44,000 net Utica acres and current natural gas production of approximately 110 MMcfe per day, from Stone Energy Corporation. The acquired acres are primarily located in Wetzel, Marshall, Tyler and Marion Counties of West Virginia. The acquired assets also included 174 Marcellus wells, 120 of which were producing at the time of the acquisition, and 20 miles of gathering pipeline.
On June 30, 2017, the Company acquired approximately 11,000 net Marcellus acres, and the associated Utica drilling rights, from a third party. The acquired acres are primarily located in Allegheny, Washington and Westmoreland Counties of Pennsylvania.
In total, the Company paid net cash of $740.1 million duringFor the year ended December 31, 20172018, as a result of the 2018 Divestitures, the Company recorded an impairment/loss on sale of long-lived assets of $2.4 billion due to the carrying value of the properties and related pipeline assets exceeding the amounts received for the 2017 acquisitions noted above. 2018 Divestitures.
The 2017 acquisitions purchase prices remain subject to customary post-closing adjustments as of December 31, 2017. The preliminary fair value assignedof the impaired assets was based on significant inputs that are not observable in the market and, as such, are considered to be Level 3 fair value measurements. See Note 4 for a description of the fair value hierarchy and Note 1 for the Company's policy on impairment of proved and unproved properties. Key assumptions included in the calculation of the fair value of the impaired assets included the following: reserves, including risk adjustments for probable and possible reserves; future commodity prices; to the acquired property, plantextent available, market-based indicators of fair value including estimated proceeds that could be realized upon a potential disposition; production rates based on the Company's experience with similar properties it operates; estimated future operating and equipment from the 2017 acquisitions asdevelopment costs; and a market-based weighted average cost of the opening balance sheet dates totaled $750.1 million. capital.
In connection with the 2017 acquisitions,closing of the 2018 Divestitures, the Company assumed approximately $5.3recorded a loss of $259.3 million during the third quarter of net current liabilities2018 related to certain capacity contracts that the Company no longer has existing production to satisfy and $4.7 million of non-current liabilities. The amounts presenteddoes not plan to use in the financial statements representfuture. The loss was recorded in impairment/loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations. The fair value of the loss for the initial measurement was based on significant inputs that are not observable in the market and, as such, is considered a Level 3 fair value measurement. The key unobservable input in the
calculation is the amount of potential future economic benefit from the contracts. See Note 4for a description of the fair value hierarchy.
8.Separation and Distribution and Discontinued Operations
On November 12, 2018, the Company completed the separation of its midstream business, which was composed of the separately operated natural gas gathering, transmission and storage and water services businesses of the Company, from its upstream business, which is composed of the natural gas, NGLs and oil development, production and sales and commercial operations of the Company (the Separation). The Separation was effected by the transfer of the midstream business from the Company to Equitrans Midstream and the distribution of 80.1% of the outstanding shares of Equitrans Midstream's common stock to the Company's estimates basedshareholders (the Distribution). The Company's shareholders received 0.80 shares of Equitrans Midstream's common stock for every one share of EQT common stock held as the close of business on preliminary valuationsNovember 1, 2018. The Company retained 19.9% of acquired assets and liabilities and are subject to change based onthe outstanding shares of Equitrans Midstream's common stock. See Note 1 for a discussion of the Company's finalizationaccounting for the investment in Equitrans Midstream and Note 5 for a discussion of asset and liability valuations.the Company's sale of a portion of its shares of Equitrans Midstream's common stock in 2020.
As a result of post-closing adjustments on its 2016 acquisitions, the Company paid $78.9 million for additional undeveloped acreage, included in the $1,130.1 million net cash inIn connection with the 2016 acquisitions disclosed above,Separation and recordedDistribution, the Company entered into several agreements with Equitrans Midstream to implement the legal and structural separation between the two companies, govern the relationship between the Company and Equitrans Midstream and allocate between the Company and Equitrans Midstream various assets, liabilities and obligations, including, among other things, employee benefits, litigation, contracts, equipment, real property, intellectual property and tax-related assets and liabilities.
non-cash adjustments which reducedIn the preliminary fair values assignedordinary course of business, the Company engages in transactions with Equitrans Midstream and its affiliates including, but not limited to, gas gathering agreements, transportation service and precedent agreements, storage agreements and water services agreements. These agreements have terms ranging from month-to-month up to 20 years.
Equitrans Midstream comprised the Company's former EQM Gathering, EQM Transmission and EQM Water segments. For all periods prior to the acquired property, plantSeparation and equipment by $14.3 million, duringDistribution, the results of operations of Equitrans Midstream are reflected as discontinued operations. The Statement of Consolidated Operations for the year ended December 31, 2017.
In total,2018 has been recast to reflect discontinued operations presentation and include certain transportation and processing expenses in continuing operations that had previously been eliminated in consolidation. Cash flows related to Equitrans Midstream are included in the Statement of Consolidated Cash Flows for the period prior to the Separation and Distribution. The results of operations of Equitrans Midstream are summarized below. The Company paid $1,130.1 million in net cash in connectionallocated transaction costs associated with the 2016 acquisitions noted above.Separation and Distribution and a portion of transaction costs associated with the 2017 acquisition of Rice Energy Inc. (the Rice Merger) to discontinued operations.
| | | | | |
| January 1, 2018 to November 12, 2018 |
| (Thousands) |
| Operating revenues | $ | 388,854 | |
| Transportation and processing | (803,858) | |
| Operation and maintenance | 99,671 | |
| Selling, general and administrative | 62,702 | |
| Depreciation | 160,701 | |
| Impairment of goodwill (a) | 267,878 | |
| Transaction costs | 93,062 | |
| Amortization of intangible assets | 36,007 | |
| Other income | 51,014 | |
| Interest expense | 88,300 | |
| Income from discontinued operations before income taxes | 435,405 | |
| Income tax expense | 61,643 | |
| Income from discontinued operations after income taxes | 373,762 | |
| Less: Net income from discontinued operations attributable to noncontrolling interests | 237,410 | |
| Net income from discontinued operations | $ | 136,352 | |
(a)Following the third quarter of 2018, and prior to the Separation and Distribution, indicators of goodwill impairment were identified in the form of announced production curtailments, which could reduce the volumetric-based fee revenues of two reporting units to which the Company's goodwill was recorded. The two reporting units, Rice Retained Midstream and RMP PA Gas Gathering, were allocated to discontinued operations as a result of the Separation and Distribution. Both of these reporting units earned a substantial portion of their revenues from volumetric-based fees, which are sensitive to changes in development plans. In estimating the fair value assigned to the acquired property, plant and equipment asof these reporting units, a combination of the opening balance sheet dates totaled $1,203.4 million: $256.2 million allocatedincome approach and the market approach was used. The discounted cash flow method income approach applies significant inputs that are not observable in the public market (Level 3), including estimates and assumptions related to future throughput volumes, operating costs, capital spending and changes in working capital. The comparable company method market approach evaluates the acquired producing wells and $947.2 million allocated to undeveloped leases. In connection with the Trans Energy Merger, the Company also acquired $1.2 millionvalue of a company using metrics of other non-current assetsbusinesses of similar size and assumed $14.4 millionindustry. The reference transaction method evaluates the value of current liabilities and $11.1 million of non-current liabilities. The $14.4 million of current liabilities included a $5.1 million note payable;company based on pricing multiples derived from similar transactions entered into by similar companies.
For the Company repaid this note in 2016. The Company also recorded a deferred tax liability of $49.0 million due to differences in the tax and book basis of the acquired assets and liabilities.
Fair Value Measurement
As these acquisitions qualified as business combinations under GAAP,year ended December 31, 2018, the fair value of the acquired assetsRice Retained Midstream reporting unit was determined using a market approach forgreater than its carrying value, but the undeveloped acreage and a discounted cash flow model undercarrying value of the income approach for the wells. Significant unobservable inputs used in the analysis included the determination of estimated developed reserves and forward pricing estimates.RMP PA Gas Gathering reporting unit exceeded its fair value. As a result, valuationimpairment of goodwill of $267.9 million was recorded with a corresponding decrease to goodwill in the acquired assets wasConsolidated Balance Sheet and allocated to discontinued operations.
The following table presents cash flows from or used in discontinued operations related to Equitrans Midstream that are included, and not separately stated, in the Statement of Consolidated Cash Flows for the year ended December 31, 2018.
| | | | | |
| January 1, 2018 to November 12, 2018 |
|
| (Thousands) |
| Cash flows from operating activities: | |
| Deferred income tax benefit | $ | (373,405) | |
| Depreciation | 160,701 | |
| Amortization of intangibles | 36,007 | |
| Impairment of goodwill | 267,878 | |
| Other income | (51,450) | |
| Share-based compensation expense | 1,841 | |
| Cash flows from investing activities: | |
| Capital expenditures | $ | (732,727) | |
| Capital contributions to Mountain Valley Pipeline, LLC (a) | (820,943) | |
| Cash flows from financing activities: | |
| Proceeds from issuance of debt | $ | 2,500,000 | |
| Proceeds in borrowings on credit facility | 3,378,500 | |
| Repayment of borrowings on credit facility | (3,219,500) | |
| Debt issuance costs | (40,966) | |
| Distributions to noncontrolling interests | (380,651) | |
| Acquisition of 25% of Strike Force Midstream LLC | (175,000) | |
(a)Mountain Valley Pipeline, LLC is a Level 3 measurement.joint venture that is constructing the Mountain Valley Pipeline. EQM owns an interest in the joint venture and makes capital contributions to the joint venture.
11.
9.Income Taxes
Income tax (benefit) expense is summarized as follows:
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Current: | | |
| | |
| | |
|
| Federal | | $ | (65,034 | ) | | $ | (82,905 | ) | | $ | 85,696 |
|
| State | | 27 |
| | (298 | ) | | 1,103 |
|
| Subtotal | | (65,007 | ) | | (83,203 | ) | | 86,799 |
|
| Deferred: | | |
| | |
| | |
|
| Federal | | (998,483 | ) | | (117,155 | ) | | (109,642 | ) |
| State | | (52,129 | ) | | (63,106 | ) | | 127,518 |
|
| Subtotal | | (1,050,612 | ) | | (180,261 | ) | | 17,876 |
|
| Total income taxes | | $ | (1,115,619 | ) | | $ | (263,464 | ) | | $ | 104,675 |
|
The Company recorded a current federalfollowing table summarizes income tax benefit in 2017 primarily as a result of carrying back federal and alternative minimum tax (AMT) net operating losses (NOLs) generated in 2016 and 2017. The Company will file carryback claims requesting a refund of a portion of(benefit) expense.
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (Thousands) |
| Current: | | | | | |
| Federal | $ | (132,625) | | | $ | (106,487) | | | $ | (513,293) | |
| State | (10,393) | | | 5,774 | | | (46,218) | |
| Subtotal | (143,018) | | | (100,713) | | | (559,511) | |
| Deferred: | | | | | |
| Federal | (131,355) | | | (213,397) | | | 20,496 | |
| State | (24,485) | | | (61,666) | | | (157,496) | |
| Subtotal | (155,840) | | | (275,063) | | | (137,000) | |
| Total income tax benefit | $ | (298,858) | | | $ | (375,776) | | | $ | (696,511) | |
For the amounts paid relating toyear ended December 31, 2020, the 2015 federal tax return. The current federal income tax benefit in 2016 primarily related to amended return refund claims filed in 2016 and 2017 for open tax years 2010 through 2013. The current federal and state income tax expense in 2015benefit consisted primarily of refunds of $117 million, including interest, related to the Company's alternative minimum tax gains generated as a result(AMT) credit carryforward, the Tax Cuts and Jobs Act of EQGP's IPO2017 (the Tax Cuts and Jobs Act) and the saleacceleration of NWV Gatheringthe receipt of such refunds with the Coronavirus Aid, Relief and Economic Security Act (CARES Act). The remainder of the tax benefit of $26 million, including interest, is related to EQMfederal and state audits that were settled in that year.2020.For the year ended December 31, 2019, the current U.S. federal income tax benefit consisted primarily of expected refunds of $120 million related to the Company's AMT credit carryforward and the Tax Cuts and Jobs Act. For the year ended December 31, 2018, the current U.S. federal income tax benefit consisted primarily of an expected refund of $141 million related to the Company's AMT credit carryforward, partly offset by $16 million of current state tax expense. The remaining current tax benefit of $435 million for the year ended December 31, 2018, was offset by current expense related to discontinued operations and will not result in additional refunds to the Company.
On December 22, 2017, the U.S. Congress enacted the law known as the Tax Cuts and Jobs Act, of 2017 (Tax Reform Legislation), which made significant changes to U.S. federal income tax law, including lowering the federal corporate tax rate to 21% from 35% beginning January 1, 2018. As a result of the change in the corporate tax rate the Company recorded a deferred tax benefit of $1.2 billion during the year ended December 31, 2017 to revalue its existing net deferred tax liabilities to the lower rate.
The Tax Reform LegislationCuts and Jobs Act also preserved deductibility of intangible drilling costs (IDCs) for U.S. federal income tax purposes, which allows the Company to deduct a portion of drilling costs in the year incurred and minimizes current taxes payable in periods of taxable income.payable. Prior to 2018, IDCs have historically beenwere limited for AMT purposes, which has resulted in the Company paying AMT in periods when no other federal taxes were currently payable. The Tax Reform LegislationCuts and Jobs Act also repealed the AMT for tax years beginning January 1, 2018 and providesprovided that existing AMT credit carryforwards can be utilizedused to offset current federal taxes owed with 50% of any remaining balance being refunded in tax years 2018 through 2020. In addition, 50%With the passing of any unusedthe CARES Act, the Company was able to accelerate these refunds to 2020. As a result of an IRS announcement in January 2019 that reversed its position that AMT credit carryforwards can be refunded during these years with any remaining AMT credit carryforward being fully refundedrefunds were subject to sequestration by the federal government at a rate equal to 6.2% of the refund, the Company reversed the related valuation allowance of $13 million in 2021. The Company had approximately $435 millionthe first quarter of AMT credit carryforward as of December 31, 2017.2019.
The Tax Reform Legislation contains several other provisions, such as limitingCuts and Jobs Act limited the deductibility of interest expense, that are not expected to haveand, as a material effect on the Company's results of operations. As of December 31, 2017,result, the Company has not completed its accountingrecorded a valuation allowance in 2019 for the effectsa portion of the Tax Reform Legislation; however, provisional amounts are recorded to revalue deferred tax assets and liabilities and reflect theinterest expense limit imposed for separate company state income tax effects relatedpurposes. During 2020, final regulations were issued that provided clarity on several issues that were beneficial to the Tax Reform Legislation. The Company also considered whether existing deferred tax amounts will be recovered in future periods underincluding (i) the new law. However,exclusion of commitment fees and debt issuance costs from the definition of interest and (ii) the inclusion of the adding back depreciation, depletion and amortization associated with cost of goods sold to arrive at adjusted taxable income. These changes eliminated the interest expense limitation for the Company is still analyzing certain aspects ofand the Tax Reform Legislation and refining calculations, which could potentially impact the measurement of these balances or potentially give rise to new deferred tax amounts. The Company will refine its estimates to incorporate new or better information as it comes available through the filing date of its 2017 U.S. income tax returnsrelated valuation allowance was reversed in the fourth quarter of 2018.2020.
The Protecting Americans from Tax Hikes (PATH) Act of 2015 was enacted on December 18, 2015 and retroactively and permanently extended the research and experimentation (R&E) tax credit for 2015 forward. The PATH Act also reinstated and extended through the end of 2017 50% bonus depreciation. In addition, the Tax Reform Legislation provides for 100% bonus depreciation on some tangible property expenditures through 2022.
The Company has federal NOLnet operating loss (NOLs) carryforwards related to the Rice Merger discussed in Note 2 and NOLs generated in 2017 in excess of the amountamounts carried back to 2015.prior years. The Company also has NOLs related toacquired in the Company's 2016 acquisition of Trans Energy, Merger discussed in Note 10,Inc., of which a nominal amount is available to be utilizedfor use annually over the next 20 years. The Tax Reform Legislation limitsCuts and Jobs Act limited the utilization of NOLs generated after December 31, 2017 that arehave been carried forward into future years to 80% of taxable income and eliminateseliminated the ability to carry NOLs back to earlier tax years for refunds of taxes paid. NOLs generated in 2018 and in future periods can be carried forward indefinitely. As a result of the CARES Act, NOLs generated in 2018, 2019 and 2020 can be carried back five years and are allowed to fully offset taxable income ignoring the 80% limitation if utilized prior to 2021.
Income tax (benefit) expensebenefit from continuing operations differed from amounts computed at the federal statutory rate of 35%21% on pre-tax income as follows:for reasons summarized below.
| | | | | Years Ended December 31, | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2020 | | 2019 | | 2018 |
| | | (Thousands) | | (Thousands) |
| Tax at statutory rate | | $ | 259,884 |
| | $ | (138,084 | ) | | $ | 149,296 |
| Tax at statutory rate | $ | (265,867) | | | $ | (335,469) | | | $ | (646,261) | |
| Federal tax reform | | (1,205,140 | ) | | — |
| | — |
| |
| State income taxes | | (52,606 | ) | | (71,613 | ) | | (7,566 | ) | State income taxes | (75,035) | | | (119,659) | | | (251,780) | |
| Valuation allowance | | 10,680 |
| | 23,808 |
| | 91,144 |
| Valuation allowance | 106,548 | | | 81,522 | | | 88,785 | |
| Noncontrolling partners’ share of earnings | | (122,365 | ) | | (112,672 | ) | | (82,850 | ) | |
| Regulatory liability/asset | | 10,488 |
| | 35,438 |
| | (35,438 | ) | |
| Federal tax credits | | (34,956 | ) | | (4,539 | ) | | (7,243 | ) | |
| Tax settlements | | Tax settlements | (33,384) | | | 0 | | | 0 | |
| Federal and state tax credits | | Federal and state tax credits | (11,628) | | | (7,908) | | | (2,400) | |
| Goodwill impairment | | Goodwill impairment | 0 | | | 0 | | | 111,470 | |
| Other | | 18,396 |
| | 4,198 |
| | (2,668 | ) | Other | (19,492) | | | 5,738 | | | 3,675 | |
| Income tax (benefit) expense | | $ | (1,115,619 | ) | | $ | (263,464 | ) | | $ | 104,675 |
| |
| Income tax benefit | | Income tax benefit | $ | (298,858) | | | $ | (375,776) | | | $ | (696,511) | |
| | Effective tax rate | | (150.2 | )% | | 66.8 | % | | 24.5 | % | Effective tax rate | 23.6 | % | | 23.5 | % | | 22.6 | % |
All of EQGP's, RMP’s and Strike Force Midstream’s income is included in theThe Company's pre-tax income (loss). However, the Company is not required to record income tax expense with respect to the portion of EQGP's and RMP’s income allocated to the noncontrolling public limited partners of EQGP, EQM and RMP or to the portion of Strike Force Midstream’s income allocated to the minority owner, which reduces the Company's effective tax rate in periods when the Company has consolidated pre-tax income and increases the Company's effective tax rate in periods when the Company has consolidated pre-tax loss.
The effective tax rate for the year ended December 31, 20172020 was lower thanhigher compared to the U.S. federal statutory rate due primarily due to the effect of the Tax Reform Legislation.state income taxes and federal and state income tax settlements, partly offset by valuation allowances that limit certain federal and state tax benefits. The primary impact of the Tax Reform Legislation on the Company's effective tax rate was to revalue the Company's deferred tax liability at the new corporate tax rate of 21%. The effective tax rate was also lower due to the effect of income allocated to the noncontrolling limited partners of EQGP, EQM and RMP and the minority owner of Strike Force Midstream as well as for federal tax credits generated during the year. These credits increased for the year ended December 31, 2017 as a result of $30.2 million of federal marginal well tax credit. The IRS Notice supporting the calculation of the credit was not published until 2017 and the Company was unable to estimate the amount of this credit absent the IRS Notice. As a result, $6.1 million of this credit recorded in 2017 related to 2016 activity.
For the year ended December 31, 2017, the Company realized a $10.5 million tax expense associated with FERC regulated assets as a result of the corporate tax rate reduction in the Tax Reform Legislation. Following the normalization rules of the IRC, this regulatory liability is amortized on a straight-line basis over the estimated remaining life of the related assets.
The effective tax rate for the year ended December 31, 20162019 was higher thancompared to the U.S. federal statutory rate due primarily to state income taxes and the release of 35% primarily duethe valuation allowance related to the effect of income allocated to the noncontrolling limited partners of EQGP and EQM. Due to theAMT sequestration, partly offset by valuation allowances that limit certain state tax benefits. The Company's consolidated pre-tax loss for the year ended December 31, 2016, EQGP's income allocated to noncontrolling limited partners increased the effective income tax rate for the year ended December 31, 2016. The increase in the effective income tax rate2018 was also partly attributablehigher compared to the tax benefit generated from pre-tax loss onU.S. federal statutory rate due primarily to state income tax paying entities and was partially offset by the $35.4 million regulatory asset write-off described in the following paragraph.
For the year ended December 31, 2015, thetaxes. The Company realized a $35.4 million regulatory assetrecognized additional state tax benefit in connection with IRS guidance received by the Company regarding a like-kind exchange of regulated assets which resulted in tax deferral for the Company. In order to be in compliance with the normalization rules of the IRC, the IRS guidance held that the deferred tax liability associated with the exchanged regulatory assets should not be considered for ratemaking purposes. As a result, during the second quarter of 2015, the Company recorded a regulatory asset equal to the taxes deferred from the exchange and an associated income tax benefit. The Company sold the assets on which it deferred the underlying taxes to EQM as part of the October 2016 Sale; as a result of the regulatory asset2018 Divestitures and deferredthe resulting shift in the Company's state apportionment in state taxing jurisdictions for natural gas and liquids sales as these sales shifted more heavily to lower taxed jurisdictions. The Company had no tax benefit reversed duringbasis in the fourth quarter of 2016.goodwill allocated to continuing operations that had been impaired in 2018.
The Company believes that it is more likely than not that the benefit from certain state NOL carryforwards and certain federal NOLs acquired in recent acquisitions will not be realized. A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2017, 20162020, 2019 and 2015,2018, positive evidence considered included the reversals of financial to taxfinancial-to-tax temporary differences, the implementation of and/or ability to employ various tax planning strategies and the estimation of future taxable income. Negative evidence considered included historical pre-tax book losses of the Company's former EQT Production business segment. A review of positive and negative evidence regarding these tax benefits resulted in the conclusion that valuation allowances for certain NOLs were warranted as it was more likely than not that the Company would not utilizeuse them prior to expiration. Uncertainties such as future commodity prices can affect the Company's calculations and its ability to utilizeuse these NOLs prior to expiration. Further, because of the Tax Cuts and Jobs Act, the Company recorded a write-off of deferred tax assets related to certain executive incentive-based awards to be paid in a future year that will not be deductible.
During 2020 and 2019, the Company recorded a partial valuation allowance against a deferred tax asset related to the unrealized loss recorded on its investment in Equitrans Midstream that it does not believe it will be able to utilize due to limitations imposed on capital losses. The Company has capital loss carryback capacity and provided a valuation allowance on the portion in excess of the carryback. Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data andon the feasibility of future tax planning strategies and may record adjustments to the related valuation allowances in future periods that could materially impact net income.
The following table reconciles the beginning and ending amount of reserve for uncertain tax positions, (excludingexcluding interest and penalties): penalties.
|
| | | | | | | | | | | | |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Balance at January 1 | | $ | 252,434 |
| | $ | 259,301 |
| | $ | 56,957 |
|
| Additions based on tax positions related to current year | | 50,469 |
| | 23,978 |
| | 152,983 |
|
| Additions for tax positions of prior years | | 8,978 |
| | 20,336 |
| | 50,688 |
|
| Reductions for tax positions of prior years | | (10,323 | ) | | (51,181 | ) | | (1,327 | ) |
| Lapse of statute of limitations | | — |
| | — |
| | — |
|
| Balance at December 31 | | $ | 301,558 |
| | $ | 252,434 |
| | $ | 259,301 |
|
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (Thousands) |
| Balance at January 1 | $ | 259,588 | | | $ | 315,279 | | | $ | 301,558 | |
| Additions for tax positions taken in current year | 5,470 | | | 19,431 | | | 8,459 | |
| Additions for tax positions taken in prior years | 7,250 | | | 8,929 | | | 14,396 | |
| Reductions for tax positions taken in prior years | (38,859) | | | (84,051) | | | (9,134) | |
| Reductions for tax positions settled with tax authorities | (58,236) | | | 0 | | | 0 | |
| Balance at December 31 | $ | 175,213 | | | $ | 259,588 | | | $ | 315,279 | |
Included in the balancebalances above are unrecognized tax benefits of $91.0 million, $150.9 million and $124.6 million that, if recognized, would affect the effective tax rate of $120.5 million, $102.0 million and $94.1 millionrates as of December 31, 2017, 20162020, 2019 and 2015,2018, respectively. Additionally, there wereAlso included in the balances above are uncertain tax positions included in the balance above of $84.1$90.3 million, $75.4$113.7 million, and $114.2$88.2 million for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively, that have beenwere recorded in the Consolidated Balance Sheets as a reduction of the related deferred tax asset for AMTgeneral business credit carryforwards and NOLs. TheDuring 2020, the Company adjusted its tax reserves as a result of settling its 2010 – 2012 amended return refund claim with the IRS by (i) reducing the uncertain tax positions and increasing the amount of the deferred tax asset wasfor AMT credits by $14.9 million, (ii) reducing the uncertain tax position offset to the deferred tax asset for Research and Experimentation credits by $35.3 million and (iii) writing down the deferred tax asset by $22.6 million to the settlement amount. In addition, in 2020, the Company settled a dispute related to its 2013 Pennsylvania returns and reduced forthe uncertain tax positions of approximately $0.3by $46.9 million and $0.5agreed to remit $33.5 million duringto the years ended December 31, 2017Commonwealth of Pennsylvania. During 2019, the Company released $84.0 million of reserves and 2016, respectively.reinstated the related deferred tax asset for AMT due to settlement of the 2013 amended return refund claim with the IRS.
Included in the tabular reconciliationbalances above atare $0.0 million, $0.7 million and $0.7 million, as of December 31, 2017, 20162020, 2019 and 2015 are $4.7 million, $5.5 million and $6.4 million,2018, respectively, for tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of tax deductions. Any disallowance of the shorter deductibility period would accelerate the payment of cash taxes to an earlier period but would not affect the Company's annual effective tax rate.
The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The Company recorded interest and penalties (income) expense of approximately $3.2$(3.8) million, $1.6$3.3 million and $1.6$3.4 million for 2017, 2016the years ended December 31, 2020, 2019 and 2015,2018, respectively. Interest and penalties of $8.4 million, $5.2$11.4 million and $3.6$15.2 million were included in the Consolidated Balance Sheets at December 31, 2017, 20162020 and 2015,2019, respectively.
As of December 31, 2017,2020, 2019 and 2018, the Company believed that, it is reasonably possible that a decrease of $42.5 million in unrecognized tax benefits related to federal tax positions may be necessary within 12 months as a result of potential settlements with, or legal or administrative guidance by, relevant taxing authorities or the lapse of applicable statutes of limitation. Aslimitation, it is reasonably possible that a decrease of December 31, 2016$125.9 million, $80.2 million and 2015, the Company did not expect any of its$33.3 million, respectively, in unrecognized tax benefits related to decreasefederal tax positions may be necessary within the next 12twelve months.
The Company's consolidated U.S. federal income tax liability of the Company has been settled with the IRS through 2009.2013. The IRS has completed its review of the 2010, 2011 and 2012 tax years and the Company is in the process of appealing its R&E tax credit claim for such years. In addition, the Company has filed refund claims relating to R&E and AMT preference adjustments for the years 2010 through 2013. These claims are under review by the IRS. The Company also is the subject of various state income tax examinations. With few exceptions, asAs of December 31, 2017,2020, with few exceptions, the Company is no longer subject to state examinations by tax authorities for years before 2012.2015.
There were no material changes to the Company’sCompany's methodology for accounting for unrecognized tax benefits during 2017.2020.
The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities:liabilities.
| | | | | As of December 31, | | December 31, |
| | | 2017 | | 2016 | | 2020 | | 2019 |
| | | (Thousands) | | (Thousands) |
| Deferred income taxes: | | |
| | |
| Deferred income taxes: | | | |
| Total deferred income tax assets | | $ | (971,184 | ) | | $ | (875,303 | ) | Total deferred income tax assets | $ | (610,821) | | | $ | (643,227) | |
| Total deferred income tax liabilities | | 2,740,084 |
| | 2,635,307 |
| Total deferred income tax liabilities | 1,982,788 | | | 2,129,041 | |
| Total net deferred income tax liabilities | | 1,768,900 |
| | 1,760,004 |
| Total net deferred income tax liabilities | 1,371,967 | | | 1,485,814 | |
| Total deferred income tax liabilities (assets): | | |
| | |
| Total deferred income tax liabilities (assets): | |
| Drilling and development costs expensed for income tax reporting | | 2,074,091 |
| | 1,473,355 |
| Drilling and development costs expensed for income tax reporting | 918,120 | | | 1,100,061 | |
| Tax depreciation in excess of book depreciation | | 644,590 |
| | 1,161,952 |
| Tax depreciation in excess of book depreciation | 1,027,179 | | | 974,520 | |
| Investment in Equitrans Midstream | | Investment in Equitrans Midstream | (94,689) | | | (109,883) | |
| Incentive compensation and deferred compensation plans | | (43,822 | ) | | (77,743 | ) | Incentive compensation and deferred compensation plans | (22,419) | | | (16,923) | |
| Net operating loss carryforwards | | (564,180 | ) | | (282,943 | ) | |
| Investment in partnerships | | (132,667 | ) | | (386,676 | ) | |
| NOL carryforwards | | NOL carryforwards | (789,544) | | | (635,446) | |
| Alternative minimum tax credit carryforward | | (435,190 | ) | | (224,428 | ) | Alternative minimum tax credit carryforward | (81,237) | | | (190,992) | |
| Federal tax credits | | (50,341 | ) | | (2,508 | ) | Federal tax credits | (79,846) | | | (59,854) | |
| Unrealized hedge (losses) gains | | 21,403 |
| | (101,430 | ) | |
| State capital loss carryforward | | State capital loss carryforward | (28,317) | | | 0 | |
| Unrealized (losses) gains | | Unrealized (losses) gains | (43,475) | | | 54,460 | |
| Interest disallowance limitation | | Interest disallowance limitation | (160) | | | (46,776) | |
| Convertible debt | | Convertible debt | 37,489 | | | 0 | |
| Other | | (7,376 | ) | | (997 | ) | Other | (1,126) | | | (6,797) | |
| Total excluding valuation allowances | | 1,506,508 |
| | 1,558,582 |
| Total excluding valuation allowances | 841,975 | | | 1,062,370 | |
| Valuation allowances | | 262,392 |
| | 201,422 |
| Valuation allowances | 529,992 | | | 423,444 | |
| Total net deferred income tax liabilities | | $ | 1,768,900 |
| | $ | 1,760,004 |
| Total net deferred income tax liabilities | $ | 1,371,967 | | | $ | 1,485,814 | |
TheDuring 2020, net deferred tax liability decrease of $1.2 billion as a result ofdecreased by $113.8 million compared to 2019 due primarily to book impairments, which are included in drilling and development costs expensed for income tax reporting but are not currently deductible for tax purposes, and the decreaseCompany's investment in the corporate tax rate in the Tax Reform Legislation and was partiallyEquitrans Midstream, partly offset by a $1.1 billion net deferredincreased tax liability recognized as a resultdepreciation in excess of the Rice Mergers discussed in Note 2.book depreciation.
As of December 31, 2017,2020, the Company had a deferred tax asset of $194.3$233.2 million, net of valuation allowances of $22.9$22.8 million, related to tax benefits from federal NOL carryforwards generated prior to 2018 and expiring between 2035 to 2037. Federal NOLs generated in 2018 and thereafter are represented by a deferred tax asset of $75.6 million and will carryforward indefinitely but will be limited to offset 80% of taxable income in each year. As of December 31, 2020, the Company had a deferred tax asset of $480.8 million, net of valuation allowances of $387.7 million, related to tax benefits from state NOL carryforwards with expiration dates ranging from 2021 to 2040. Due to a decrease in state apportionment rates and impairment of assets, the Company will have less realizable NOLs in future years on a separate company basis and, as such, in 2020 recorded a valuation allowance on its property, plant and equipment state deferred tax asset of $0.6 million. In 2020, the Company incurred an unrealized loss on its investment in Equitrans Midstream. This investment is a capital asset for tax purposes and capital losses can only be utilized to offset a capital gain and are limited to being carried back three years and forward five years for potential utilization. Due to these limitations, the Company also recorded a valuation allowance on the deferred tax asset for its retained equity stake of Equitrans Midstream of $62.4 million for separate company state income tax reporting purposes and $56.4 million for federal.
As of December 31, 2019, the Company had a deferred tax asset of $218.8 million, net of valuation allowances of $22.8 million, related to tax benefits from federal NOL carryforwards expiring in 20362037. Federal NOLs generated in 2018 and forward will carryforward indefinitely but will be limited to 2037.offset 80% of taxable income in each year. As of December 31, 2017,2019, the Company had a deferred tax asset of $130.0$416.7 million, net of valuation allowances of $217.0$324.1 million, related to tax benefits from state NOL carryforwards with various expiration dates ranging from 20182020 to 2037. On October 30, 2017, Pennsylvania enacted2039. Due to a changedecrease in state apportionment rates and impairment of assets, the Company will have less realizable NOLs in future years and, as such, had to record a valuation allowance on its property, plant and equipment state deferred tax asset of $4.5 million in 2019. Additionally, for separate company state income tax reporting purposes, the Tax Cuts and Jobs Act interest deduction limitation resulted in a valuation allowance of $21.3 million recorded in 2019. In 2019, the Company incurred an unrealized loss on Pennsylvania NOL utilization to 35%its investment in
Equitrans Midstream. This investment is a capital asset for tax purposes and capital losses can only be utilized to offset a capital gain and are limited to being carried back three years beginning in 2018 and forward five years for potential utilization. Due to 40% of taxable income for tax years beginning in 2019 and thereafter. As a result, the Company's valuation allowance for state NOLs was reduced by $21.2 million during 2017. In addition,these limitations, the Company also recorded a valuation allowance of $22.5 million on AMT credits related to the federal sequestration of refunds, which reduces refunds claims for NOLs by 6.6% in fiscal 2017. As of December 31, 2016, the Company had a deferred tax asset recorded for its retained equity stake of $81.5Equitrans Midstream of $42.4 million net of valuation allowances of $201.4for separate company state income tax reporting purposes and $8.3 million related to tax benefits from state NOL carryforwards with various expiration dates ranging from 2018 to 2035.for federal.
As discussed in Note 1, effective forFor the year ended December 31, 2017, EQT adopted ASU No. 2016-09 to simplify accounting for employee share-based payment transactions and eliminated excess tax benefits. The2019, the Company recorded tax benefits
of $0.9a $90.9 million for the year ended December 31, 2016, in the Consolidated Financial Statements as additionsadjustment to common shareholders’ equity, which reduced taxes payable for the respective year.
12.Equity in Nonconsolidated Investments
The Company, through its ownership interest in EQM, has an ownership interest in the MVP Joint Venture, a nonconsolidated investment that is accounted for under the equity method of accounting. The following table summarizes the Company's equity in the MVP Joint Venture:
|
| | | | | | | | | | | | | | |
| | | | | Interest | | Ownership as of | | As of December 31, |
| Investees | | Location | | Type | | December 31, 2017 | | 2017 | | 2016 |
| | | | | | | | | (Thousands) |
| MVP Joint Venture | | USA | | Joint | | 45.5% | | $ | 460,546 |
| | $ | 184,562 |
|
The Company recorded equity income for 2017, 2016retained earnings and 2015additional paid-in-capital related to the MVP Joint Venture of $22.2 million, $9.9 millionSeparation and $2.6 million, respectively, within other income on the Statements of Consolidated Operations.
In December 2017, the MVP Joint Venture issued a capital call notice to MVP Holdco for $105.7 million, of which $27.2 million was paid in January 2018Distribution. The Separation and the remaining $78.5 million is expected to be paid in February 2018. The capital contribution payable is recorded in other current liabilities on the Consolidated Balance Sheet as of December 31, 2017 with a corresponding increase to investment in unconsolidated subsidiary.
The MVP Joint Venture has been determined to be a variable interest entity because it has insufficient equity to finance activities during the construction stage of the project. EQM is not the primary beneficiary because it does not have the power to direct the activities of the MVP Joint Venture that most significantly impact its economic performance. Certain business decisions, including, but not limited to, decisions with respect to operating and construction budgets, project construction schedule, material contracts or precedent agreements, indebtedness, significant acquisitions or dispositions, material regulatory filings and strategic decisions require the approval of owners holding more than a 66 2/3% interestDistribution resulted in the MVP Joint Venture and no one member owns more thanrecognition of a 66 2/3% interest.
On January 21, 2016, affiliates of Consolidated Edison, Inc. (ConEd) acquiredtax gain related to a 12.5% interest in the MVP Joint Venture and entered into 20-year firm capacity commitments for approximately 0.25 Bcf per day on both the MVP and EQM’s transmission system (the ConEd Transaction). Aspre-Separation transaction. Recognition occurred as a result of Equitrans Midstream exiting the ConEd Transaction, EQM's interestCompany's consolidated federal filing group. The gain amount reported in the MVP Joint Venture decreased by 8.5%tax return was different than the amount estimated in the 2018 financial statements; therefore, the Company recorded a return-to-provision adjustment in 2019. This adjustment impacts the amount of deferred taxes transferred to 45.5%,Equitrans Midstream as of the Separation and ConEd reimbursed EQM $12.5 million, which represented EQM's proportional capital contributions to the MVP Joint Venture through theDistribution date of the transaction.November 12, 2018.
As of December 31, 2017, EQM had issued a $91 million performance guarantee in favor of the MVP Joint Venture to provide performance assurances for MVP Holdco's obligations to fund its proportionate share of the construction budget for the MVP.
10.Debt
As of December 31, 2017, EQM's maximum financial statement exposure related to the MVP Joint Venture was approximately $551.5 million, which consists of the investment in nonconsolidated entity balance of $460.5 million on the Consolidated Balance Sheet as of December 31, 2017 and amounts which could have become due under EQM's performance guarantee as of that date. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| | Principal Value | | Carrying Value (a) | | Fair Value (b) | | Principal Value | | Carrying Value (a) | | Fair Value (b) |
| | (Thousands) |
| Credit Facility expires July 2022 | $ | 300,000 | | | $ | 300,000 | | | $ | 300,000 | | | $ | 294,000 | | | $ | 294,000 | | | $ | 294,000 | |
| Term Loan Facility due May 31, 2021 | 0 | | | 0 | | | 0 | | | 1,000,000 | | | 999,353 | | | 999,353 | |
| Senior notes: | | | | | | | | | | | |
| Floating rate notes due October 1, 2020 | 0 | | | 0 | | | 0 | | | 500,000 | | | 499,238 | | | 500,290 | |
| 2.50% notes due October 1, 2020 | 0 | | | 0 | | | 0 | | | 500,000 | | | 499,228 | | | 500,950 | |
| 8.81% to 9.00% series A notes due 2020 – 2021 | 24,000 | | | 24,000 | | | 25,232 | | | 35,200 | | | 35,200 | | | 37,380 | |
| 4.875% notes due November 15, 2021 | 125,118 | | | 124,943 | | | 128,231 | | | 750,000 | | | 747,571 | | | 774,173 | |
| 3.00% notes due October 1, 2022 | 568,823 | | | 566,689 | | | 578,055 | | | 750,000 | | | 745,579 | | | 737,025 | |
| 7.42% series B notes due 2023 | 10,000 | | | 10,000 | | | 10,038 | | | 10,000 | | | 10,000 | | | 10,788 | |
| 7.875% notes due February 1, 2025 (c) | 1,000,000 | | | 992,905 | | | 1,146,250 | | | 0 | | | 0 | | | 0 | |
| 1.75% convertible notes due May 1, 2026 | 500,000 | | | 359,635 | | | 587,385 | | | 0 | | | 0 | | | 0 | |
| 7.75% debentures due July 15, 2026 | 115,000 | | | 112,224 | | | 137,025 | | | 115,000 | | | 111,727 | | | 129,466 | |
| 3.90% notes due October 1, 2027 | 1,250,000 | | | 1,242,182 | | | 1,249,400 | | | 1,250,000 | | | 1,241,024 | | | 1,167,763 | |
| 5.00% notes due January 15, 2029 | 350,000 | | | 344,106 | | | 371,469 | | | 0 | | | 0 | | | 0 | |
| 8.750% notes due February 1, 2030 (c) | 750,000 | | | 743,726 | | | 924,510 | | | 0 | | | 0 | | | 0 | |
| Note payable to EQM | 105,056 | | | 105,056 | | | 130,464 | | | 110,059 | | | 110,059 | | | 128,241 | |
| Total debt | 5,097,997 | | | 4,925,466 | | | 5,588,059 | | | 5,314,259 | | | 5,292,979 | | | 5,279,429 | |
| Less: Current portion of debt | 154,336 | | | 154,161 | | | 159,943 | | | 16,204 | | | 16,204 | | | 17,436 | |
| Long-term debt | $ | 4,943,661 | | | $ | 4,771,305 | | | $ | 5,428,116 | | | $ | 5,298,055 | | | $ | 5,276,775 | | | $ | 5,261,993 | |
(a)For the note payable to EQM, the principal value represents the carrying value. For all other debt, the principal value less the unamortized debt issuance costs and debt discounts represents the carrying value. 13.Consolidated Variable Interest Entities(b)The carrying value of borrowings under the Company's credit facility and Term Loan Facility approximate fair value as the interest rates are based on prevailing market rates; therefore, they are a Level 1 fair value measurement. For the note payable to EQM, fair value is measured using Level 3 inputs. For all other debt, fair value is measured using Level 2 inputs. See Note 4 for a description of the fair value hierarchy.
(c)See discussion below of the interest rate on these notes under "Adjustable Rate Notes."
As of December 31, 2020, aggregate maturities for the Company's senior notes were $149 million in 2021, $569 million in 2022, $10 million in 2023, $0 million in 2024, $1,000 million in 2025 and $2,965 million thereafter. The indentures governing the Company's long-term indebtedness contain certain restrictive financial and operating covenants, including covenants that restrict, among other things, the Company's ability to incur, as applicable, indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions.
$2.5 Billion Credit Facility. The Company adopted ASU No. 2015-02, Consolidation in the first quarter of 2016 and, as a result, EQT determined EQGP and EQM to be variable interest entities. Following the Rice Merger, the Company concluded that RMP and Strike Force Midstream each meet the criteria for variable interest entity classification. Through EQT's ownership and control of EQGP's general partner, EQM's general partner, RMP's general partner and Strike Force Midstream Holdings, EQT has the power to direct the activities that most significantly impact the economic performance of EQGP, EQM, RMP and Strike Force Midstream. In addition, through EQT's limited partner interest in EQGP and EQGP's general partner interest, limited partner interest and IDRs in EQM, EQT has the obligation to absorb the losses of EQGP and EQM and the right to receive benefits from EQGP and EQM, in accordance with such interests. Furthermore, through EQT's general partner interest, limited partner interest and IDRs in RMP and majority ownership interest in Strike Force Midstream, EQT has the obligation to absorb the losses of RMP and Strike Force Midstream and the right to receive benefits from RMP and Strike Force Midstream, in accordance with such interests. As EQT has a controlling financial interest in EQGP, EQM, RMP and Strike Force Midstream and is the primary beneficiary, EQT consolidates EQGP, EQM, RMP and Strike Force Midstream.
The key risks associated with the operations of EQGP, EQM, RMP and Strike Force Midstream, as applicable, are:
EQGP's only cash-generating assets consist of its partnership interests in EQM; therefore, its cash flow is dependent upon the ability of EQM to make cash distributions to its partners;
EQM and RMP depend on EQT for a substantial majority of their revenues and future growth; therefore, EQM and RMP are indirectly subject to the business risks of EQT;
EQM's natural gas gathering, transmission and storage services, RMP's natural gas gathering, compression and water services, and Strike Force Midstream's gathering and compression services are subject to extensive regulation by federal, state and local regulatory authorities and subject to stringent environmental laws and regulations, which may expose EQM, RMP and Strike Force Midstream to significant costs and liabilities;
Expanding EQM, RMP and Strike Force Midstream's businesses by constructing new midstream assets subjects EQM, RMP, and Strike Force Midstream to risks. If EQM, RMP and Strike Force Midstream do not complete these expansion projects, their future growth may be limited;
EQM, RMP and Strike Force Midstream are subject to numerous hazards and operational risks which include, but are not limited to, ruptures, fires, explosions, leaks and damage to pipelines, facilities, equipment and surrounding properties caused by natural disasters, acts of sabotage and terrorism, and inadvertent damage; and
Certain of the services EQM provides on its transmission and storage system are subject to long-term, fixed-price "negotiated rate" contracts that are not subject to adjustment, even if EQM's cost to perform such services exceeds the revenues received from such contracts, and, as a result, EQM's costs could exceed its revenues received under such contracts.
See further discussion of the impact that EQT's ownership and control of EQM, EQGP , RMP and Strike Force Midstream have on EQT's financial position, results of operations and cash flows in Notes 3, 4 and 5 for EQM, EQGP, and RMP, respectively, and in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Annual Report on Form 10-K for the year ended December 31, 2017.
The following table presents amounts included in the Consolidated Balance Sheets that were for the use or obligation of EQGP or EQM as of December 31, 2017 and 2016.
|
| | | | | | | | |
| Classification | | December 31, 2017 | | December 31, 2016 |
| | | (Thousands) |
| Assets: | | |
| | |
|
| Cash and cash equivalents | | $ | 2,857 |
| | $ | 60,453 |
|
| Accounts receivable | | 28,804 |
| | 20,662 |
|
| Prepaid expenses and other | | 8,470 |
| | 5,745 |
|
| Property, plant and equipment, net | | 2,804,059 |
| | 2,578,834 |
|
| Other assets | | 483,004 |
| | 206,104 |
|
| Liabilities: | | | | |
| Accounts payable | | $ | 47,042 |
| | $ | 35,831 |
|
| Other current liabilities | | 133,531 |
| | 32,242 |
|
| Credit facility borrowings | | 180,000 |
| | — |
|
| Senior Notes | | 987,352 |
| | 985,732 |
|
| Other liabilities and credits | | 20,273 |
| | 9,562 |
|
The following table summarizes EQGP and EQM's Statements of Consolidated Operations and Cash Flows for the years ended December 31, 2017, 2016 and 2015, inclusive of affiliate amounts.
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Operating revenues | | $ | 834,096 |
| | $ | 735,614 |
| | $ | 632,936 |
|
| Operating expenses | | 256,403 |
| | 211,630 |
| | 183,956 |
|
| Other (expenses) income | | (8,773 | ) | | 11,010 |
| | (14,980 | ) |
| Net income | | $ | 568,920 |
| | $ | 534,994 |
| | $ | 434,000 |
|
| | | | | | | |
| Net cash provided by operating activities | | $ | 647,828 |
| | $ | 535,357 |
| | $ | 488,329 |
|
| Net cash used in investing activities | | $ | (456,968 | ) | | $ | (732,033 | ) | | $ | (1,043,822 | ) |
| Net cash (used in) provided by financing activities | | $ | (248,456 | ) | | $ | (103,828 | ) | | $ | 735,712 |
|
The following table presents summary information of assets and liabilities of RMP included in the Company’s Consolidated Balance Sheets that are for the use or obligation of RMP.
|
| | | | |
| Classification | | December 31, 2017 |
| | | (Thousands) |
| Assets: | | |
| Cash | | $ | 10,538 |
|
| Accounts receivable | | 12,246 |
|
| Other current assets | | 1,327 |
|
| Property and equipment, net | | 1,431,802 |
|
| Goodwill | | 1,346,918 |
|
| Liabilities: | | |
| Accounts payable | | $ | 4 |
|
| Other current liabilities | | 28,830 |
|
| Credit facility borrowings | | 286,000 |
|
| Other long-term liabilities | | 9,360 |
|
The following table presents summary information for RMP’s financial performance included in the Consolidated Statements of Operations and Cash Flows for the period from November 13, 2017 through December 31, 2017, inclusive of affiliate amounts.
|
| | | | |
| | | For the period November 13, 2017 through December 31, 2017 |
| | | (Thousands) |
| Operating revenues | | $ | 44,219 |
|
| Operating expenses | | 18,274 |
|
| Other expenses | | (811 | ) |
| Net income | | $ | 25,134 |
|
| | | |
| Net cash provided by operating activities | | $ | 22,430 |
|
| Net cash used in investing activities | | $ | (34,553 | ) |
| Net cash provided by financing activities | | $ | 9,959 |
|
The following table presents summary information of assets and liabilities of Strike Force Midstream included in the Company’s Consolidated Balance Sheets that are for the use or obligation of Strike Force Midstream.
|
| | | |
| | December 31, 2017 |
| | (Thousands) |
| Assets: | |
| Cash | $ | 43,938 |
|
| Accounts receivable | 12,477 |
|
| Property and equipment, net | 356,346 |
|
| Intangible Assets | 457,992 |
|
| Liabilities: | |
| Other current liabilities | $ | 24,341 |
|
The following table presents summary information for Strike Force Midstream’s financial performance included in the Consolidated Statements of Operations and Cash Flows for the period from November 13, 2017 through December 31, 2017, inclusive of affiliate amounts.
|
| | | | |
| | | For the period November 13, 2017 through December 31, 2017 |
| | | (in thousands) |
| Operating revenues | | $ | 9,214 |
|
| Operating expenses | | 6,330 |
|
| Other (expenses) income | | 52 |
|
| Net income | | $ | 2,936 |
|
| | | |
| Net cash provided by operating activities | | $ | 8,588 |
|
| Net cash used in investing activities | | $ | (36,190 | ) |
| Net cash provided by financing activities | | $ | 26,951 |
|
14.Revolving Credit Facilities
EQT $2.5 Billion Facility
In July 2017, the Company amended and restated its $1.5 billion revolving credit facility to extend the term tothat expires in July 2022. The Company may request two2 one-year extensions of the expiration date, the approval of which is subject to satisfaction of certain conditions. On November 13, 2017, in connection with the consummationThe
Company may, on a one-time basis, request that the lenders’lenders' commitments be increased to an aggregate of up to $3.0 billion.billion, subject to certain terms and conditions. Each lender in the facility may decide if it will increase its commitment. The credit facility may be used for working capital, capital expenditures, share repurchases and any other lawful corporate purposes. The credit facility is underwritten by a syndicate of 1920 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by the Company.
Under the terms of the credit facility, the Company may obtain base rate loans or fixed period Eurodollar rate loans denominated in U.S. dollars. Base rate loans bear interest at a base rate plus a margin based on the Company’s then currentCompany's credit ratings. Fixed period Eurodollar rate loans bear interest at a Eurodollar rate plus a margin based on the Company’s then currentCompany's credit ratings. Based on the Company's senior notes credit rating as of December 31, 2020, the margin on base rate loans was 1.00% and the margin on Eurodollar rate loans was 2.00%.
The Company is not required to maintain compensating bank balances. The Company’sCompany's debt issuer credit ratings, as determined by Moody's, S&P Moody’s or Fitch Ratings Service (Fitch) on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with the credit facility in addition to the interest rate charged by the counterparties on any amounts borrowed against the credit facility; the lower the Company’sCompany's debt credit rating, the higher the level of fees and borrowing rate.
The Company had $1.3 billion of borrowings and $159.4 million letters of credit outstanding under its credit facility as of December 31, 2017. The Company had no borrowings or letters of credit outstanding under its revolving credit facility as of December 31, 2016 and 2015 or at any time during the years ended December 31, 2016 and 2015. The Company incurred commitment fees averaging approximately 20, 23 and 23 basis points for the years ended December 31, 2017, 2016 and 2015, respectively, to maintain credit availability under its credit facility.
The maximum amount of outstanding borrowings at any time under the credit facility during the year ended December 31, 2017 was $1.4 billion, and the average daily balance of borrowings outstanding was approximately $190.9 million at a weighted average annual interest rate of approximately 2.8%.
The Company’sCompany's credit facility contains various provisions that, if not complied with, could result in termination of the credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the credit facility relate toare the maintenance of a debt-to-total capitalization ratio and limitations on transactions with affiliates. The credit facility contains financial covenants that require a total debt-to-total capitalization ratio no greater than 65%. The, the calculation of this ratiowhich excludes the effects of accumulated OCI. As of December 31, 2017,2020, the Company was in compliance with all debt provisions and covenants.
EQM $1.0 Billion Facility
In July 2017, EQM amended and restated its credit facility to increase the borrowing capacity under the facility from $750 million to $1 billion and to extend the term to July 2022. Subject to certain terms and conditions, the $1 billion credit facility has an accordion feature that allows EQM to increase the available borrowings under the facility by up to an additional $500 million. Each lender in the facility may decide if it will increase its commitment. The credit facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes. The credit facility is underwritten by a syndicate of 19 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by EQM. The Company is not a guarantorhad $0.8 billion of EQM’s obligations under the credit facility. Obligations under the revolving portion of the credit facility are unsecured.
Under the terms of its credit facility, EQM may obtain base rate loans or fixed period Eurodollar rate loans denominated in U.S. dollars. Base rate loans bear interest at a base rate plus a margin based on EQM’s then current credit rating. Fixed period Eurodollar rate loans bear interest at a Eurodollar rate plus a margin based on EQM’s then current credit ratings.
EQM is not required to maintain compensating bank balances under its $1 billion credit facility. EQM’s debt issuer credit ratings, as determined by S&P, Moody’s and Fitch on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its credit facility in addition to the interest rate charged by the counterparties on any amounts borrowed against the credit facility; the lower EQM’s debt credit rating, the higher the level of fees and borrowing rate.
EQM had $180.0 million borrowings and no letters of credit outstanding under its $1 billion credit facility as of December 31, 2017. EQM had no borrowings and no letters of credit outstanding under its credit facility as of December 31, 2016.2020 and 0 letters of credit outstanding under its credit facility as of December 31, 2019. For each of the years ended December 31, 2017, 20162020, 2019 and 2015, EQM2018, the Company incurred commitment fees averagingof approximately 28, 20 23 and 2320 basis points, respectively, on the undrawn portion of its credit facility to maintain credit availability under itsavailability.
Under the Company's credit facility.
During 2017, 2016facility, for the years ended December 31, 2020, 2019 and 2015,2018, the maximum amounts of EQM's outstanding borrowings under the credit facility at any time were $260 million, $401 million$0.7 billion, $1.1 billion and $404 million,$1.6 billion, respectively, the average daily balances were approximately $74$148 million, $77$340 million and $261$854 million, respectively, and interest was incurred at weighted average annual interest rates of 2.8%2.3%, 2.0%3.8% and 1.7%3.4%, respectively.
EQM’s creditTerm Loan Facility. The Company had a $1.0 billion unsecured term loan facility contains various provisions(the Term Loan Facility) that if not complied with, could resultwas scheduled to mature in terminationMay 2021. In 2019, the Company used the proceeds from borrowings of the credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default$1.0 billion under the credit facility relateTerm Loan Facility to maintenancerepay $700 million aggregate principal amount of a permitted leverage ratio, limitations on transactions with affiliates, limitations on restricted payments, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of and certain other defaults under other financial obligations and change of control provisions. Under EQM's $1 billion credit facility, EQM is required to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (or not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions). As of December 31, 2017, EQM was in compliance with all debt provisions and covenants.
See also the discussion of the revolving loan agreement between EQT and EQM in Note 4 to the Consolidated Financial Statements.
RMP $850 Million Facility
Rice Midstream OpCo LLC (RMP OpCo), a direct wholly owned subsidiary of RMP, has an $850 million, secured revolving credit facility that expires in December 2019. Subject to certain terms and conditions, the credit facility has an accordion feature that allows RMP OpCo to increase the available8.125% senior notes, repay outstanding borrowings under the facility by up to an additional $200 million. Each lender in the facility may decide if it will increase its commitment. TheCompany's $2.5 billion credit facility is availableand pay accrued interest and fees and expenses related to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions, to repurchase units and for general partnership purposes. the term loan agreement. Borrowings under the Term Loan Facility that are repaid may not be reborrowed.
The Company is not a guarantor ofused proceeds from the obligations of RMP or anyoffering of its subsidiaries underConvertible Notes (see below), income tax refunds received during 2020 (see Note 9) and proceeds from the credit facility. The credit facility is secured by mortgages and other security interests2020 Divestiture (see Note 7) to fully repay its Term Loan Facility on substantially all of RMP’s properties and is guaranteed by RMP and its restricted subsidiaries. The credit facility is underwritten by a syndicate of 18 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings thereunder by RMP OpCo.
June 30, 2020. Under the terms ofCompany's Term Loan Facility, from January 1, 2020 through June 30, 2020, the RMP credit facility, RMP OpCo may obtain base rate loans or fixed period Eurodollar rate loans denominated in U.S. dollars. Base rate loans bearaverage daily balance was approximately $692 million and interest was incurred at a base rate plus a margin based on RMP's leverage ratio. Fixed period Eurodollar rate loans bear interest at a Eurodollar rate plus a margin based on the leverage ratio then in effect.
RMP is not required to maintain compensating bank balances under its credit facility. RMP’s leverage ratio in effect from time to time determines the level of fees associated with its credit facility in addition to theweighted average annual interest rate charged byof 2.6%. For the counterparties on any amounts borrowed against the lines of credit.
As ofperiod May 31, 2019 through December 31, 2017, RMP OpCo had $286 million of borrowings and $1 million of letters of credit outstanding under2019, the credit facility. The average daily outstanding balance of borrowings at any time under the credit facility during the period from November 13, 2017 to December 31, 2017 was approximately $268 million$1.0 billion and interest was incurred at a weighted average annual interest rate of 3.1%. RMP OpCo pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.
The credit facility contains various provisions that, if not complied with, could result in termination of the agreement, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the RMP credit facility relate to maintenance of certain financial ratios, as described below, limitations on certain investments and acquisitions, limitations on transactions with affiliates, limitations on restricted payments, limitations on the incurrence of additional indebtedness, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of and certain other defaults under other financial obligations and change of control provisions. The RMP credit facility requires RMP to maintain the following financial ratios: an interest coverage ratio of at least 2.50 to 1.0; a consolidated total leverage ratio of not more than 4.75 to 1.0, and after electing to issue senior unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.0 (with certain increases for measurement periods following the completion of certain acquisitions); and if RMP elects to issue senior unsecured notes, a consolidated senior secured leverage ratio of not more than 3.50 to 1.0. As of December 31, 2017, RMP and RMP OpCo were in compliance with all credit facility provisions and covenants.
15.Senior Notes
|
| | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2017 | | December 31, 2016 |
| | | Principal Value | Carrying Value (a) | Fair Value (b) | | Principal Value | Carrying Value (a) | Fair
Value (b) |
| | | (Thousands) |
| 5.15% Notes, due March 1, 2018 | | $ | — |
| $ | — |
| $ | — |
| | $ | 200,000 |
| $ | 199,545 |
| $ | 207,180 |
|
| 6.50% Notes, due April 1, 2018 | | — |
| — |
| — |
| | 500,000 |
| 499,089 |
| 527,205 |
|
| 8.13% Notes, due June 1, 2019 | | 700,000 |
| 698,918 |
| 755,153 |
| | 700,000 |
| 698,106 |
| 789,271 |
|
Floating Rate Notes due October 1, 2020
| | 500,000 |
| 497,206 |
| 501,325 |
| | — |
| — |
| — |
|
| 2.50% Notes due October 1, 2020 | | 500,000 |
| 497,169 |
| 497,670 |
| | — |
| — |
| — |
|
| 4.88% Notes, due November 15, 2021 | | 750,000 |
| 744,920 |
| 801,953 |
| | 750,000 |
| 743,595 |
| 801,218 |
|
| 3.00% Notes due October 1, 2022 | | 750,000 |
| 742,364 |
| 743,550 |
| | — |
| — |
| — |
|
| 4.00% EQM Notes, due August 1, 2024 | | 500,000 |
| 494,939 |
| 504,110 |
| | 500,000 |
| 494,170 |
| 493,125 |
|
| 7.75% debentures, due July 15, 2026 | | 115,000 |
| 110,732 |
| 135,024 |
| | 115,000 |
| 110,235 |
| 141,800 |
|
| 4.125% EQM Notes, due December 1, 2026 | | 500,000 |
| 492,413 |
| 501,990 |
| | 500,000 |
| 491,562 |
| 488,460 |
|
| 3.90% Notes due October 1, 2027 | | 1,250,000 |
| 1,238,707 |
| 1,245,200 |
| | — |
| — |
| — |
|
| Medium-term notes: | | |
| | | | |
| | |
| 7.42% Series B, due 2023 | | 10,000 |
| 10,000 |
| 11,433 |
| | 10,000 |
| 9,998 |
| 11,677 |
|
| 7.6% Series C, due 2018 | | 8,000 |
| 7,999 |
| 8,012 |
| | 8,000 |
| 7,991 |
| 8,375 |
|
| 8.7% to 9.0% Series A, due 2020 through 2021 | | 35,200 |
| 35,187 |
| 40,510 |
| | 35,200 |
| 35,168 |
| 41,906 |
|
| | | 5,618,200 |
| 5,570,554 |
| 5,745,930 |
| | 3,318,200 |
| 3,289,459 |
| 3,510,217 |
|
| Less Senior Notes payable within one year | | 8,000 |
| 7,999 |
| 8,012 |
| | — |
| — |
| — |
|
| Total Senior Notes | | $ | 5,610,200 |
| $ | 5,562,555 |
| $ | 5,737,918 |
| | $ | 3,318,200 |
| $ | 3,289,459 |
| $ | 3,510,217 |
|
(a) Carrying value represents principal value less unamortized debt issuance costs and debt discounts.
(b) Fair value is measured using Level 2 inputs.
Adjustable Rate Notes.On October 4, 2017,January 21, 2020, the Company completedissued $1.0 billion aggregate principal amount of 6.125% senior notes due February 1, 2025 and $750 million aggregate principal amount of 7.000% senior notes due February 1, 2030 (together, the public offering (the 2017Adjustable Rate Notes). The Company used the net proceeds from the Adjustable Rate Notes Offering) ofto repay $500 million aggregate principal amount of Floating Rate Notes due 2020 (the Floating Rate Notes),the Company's floating rate notes, $500 million aggregate principal amount of the Company's 2.50% Senior Notes due 2020 (the 2020 Notes), $750 senior notes, $500 million aggregate principal amount of 3.00% Seniorthe Company's 4.875% senior notes and $200 million of the Company's Term Loan Facility borrowings.
The covenants of the Adjustable Rate Notes due 2022 (the 2022 Notes)are consistent with the Company's existing senior unsecured notes, with an additional interest rate adjustment provision that provides for adjustments to the interest rates on the Adjustable Rate Notes based on credit ratings assigned by Moody's, S&P and $1,250Fitch to the Company's senior notes. As a result of changes to the Company's senior notes credit rating, the interest rate on the 6.125% senior notes and the 7.000% senior notes was 7.875% and
8.750%, respectively, as of December 31, 2020. The adjusted interest rate under the Adjustable Rate Notes cannot exceed 2% of the original interest rate first set forth on the face of the Adjustable Rate Notes; however, if the Company's credit ratings improve, the interest rate under the Adjustable Rate Notes could be reduced to as low as the original interest rate set forth on the face of the Adjustable Rate Notes.
Convertible Notes. On April 28, 2020, the Company issued $500 million aggregate principal amount of 3.90% Senior1.75% convertible senior notes (the Convertible Notes) due May 1, 2026 unless earlier redeemed, repurchased or converted. The Convertible Notes due 2027 (the 2027 Notes,were issued in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. After deducting offering costs of $16.9 million and together withCapped Call Transactions (defined and discussed below) costs of $32.5 million, the Floating Rate Notes, the 2020 Notes and the 2022 Notes, the 2017 Notes). The Company received net proceeds from the 2017offering of $450.6 million were used to repay $450 million of the Company's Term Loan Facility borrowings as well as for general corporate purposes.
Holders of the Convertible Notes Offeringmay convert their Convertible Notes, at their option, at any time prior to the close of approximately $2,974.2 million,business on January 30, 2026 under the following circumstances:
•during any quarter commencing after the quarter ended June 30, 2020 as long as the last reported price of EQT common stock for at least 20 trading days (consecutive or otherwise) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding quarter is greater than or equal to 130% of the conversion price on each such trading day;
•during the 5-business-day period after any 5-consecutive-trading-day period (the measurement period) in which the trading price per $1,000 principal amount of the Convertible Notes for each trading day of the measurement period is less than 98% of the product of the last reported price of EQT common stock and the conversion rate for the Convertible Notes on each such trading day;
•if the Company calls any or all of the Convertible Notes for redemption, at any time prior to the close of business on the second scheduled trading day immediately preceding such redemption date; and
•upon the occurrence of certain corporate events set forth in the Convertible Notes indenture.
On or after February 1, 2026, holders of the Convertible Notes may convert their Convertible Notes, at their option, at any time until the close of business on the second scheduled trading date immediately preceding May 1, 2026.
Upon conversion of the Convertible Notes, the Company intends to use a combined settlement approach to satisfy its settlement obligation by paying or delivering to holders of the Convertible Notes cash equal to the principal amount of the obligation and EQT common stock for amounts that exceed the principal amount of the obligation.
The Company may not redeem the Convertible Notes prior to May 5, 2023. On or after May 5, 2023 and prior to February 1, 2026, the Company may redeem for cash all or any portion of the Convertible Notes, at its option, at a redemption price equal to 100% of the principal amount of the Convertible Notes to be redeemed plus accrued and unpaid interest up to the redemption date as long as the last reported price per share of EQT common stock has been at least 130% of the conversion price in effect for at least 20 trading days (consecutive or otherwise) during any 30-consecutive-trading-day period ending on the trading day immediately preceding the date on which the Company used, together with other cash on hand and borrowings underdelivers notice of redemption. A sinking fund is not provided for the Company’s $2.5 billion credit facility, to fundConvertible Notes.
The initial conversion rate for the cash portionConvertible Notes is 66.6667 shares of EQT common stock per $1,000 principal amount of the considerationConvertible Notes, which is equivalent to an initial conversion price of $15.00 per share of EQT common stock. The initial conversion price represents a premium of 20% to the $12.50 per share closing price of EQT common stock on April 23, 2020. The conversion rate is subject to adjustment under certain circumstances. In addition, following certain corporate events that occur prior to May 1, 2026 or if the Company delivers notice of redemption, the Company will, in certain circumstances, increase the conversion rate for a holder who elects to convert its Convertible Notes in connection with such corporate event or notice of redemption.
In connection with the Convertible Notes offering, the Company entered into privately negotiated capped call transactions (the Capped Call Transactions), the purpose of which is to reduce the potential dilution to EQT common stock upon conversion of the Convertible Notes and/or offset any cash payments the Company is required to make in excess of the principal amount of such obligation, with such reduction and expensesoffset subject to a cap. The Capped Call Transactions have an initial strike price of $15.00 per share of EQT common stock and an initial capped price of $18.75 per share of EQT common stock, each of which are subject to certain customary adjustments.
For accounting purposes, the Company separated the Convertible Notes into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of similar debt instruments that do not have
associated convertible features. The carrying amount of the equity component, representing the conversion option, was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes. The equity component is not remeasured as long as it continues to meet the condition for equity classification. The excess of the principal amount of the liability component over its carrying amount (the debt discount) will be amortized to interest expense over the term of the Convertible Notes, which is approximately 6 years, at an effective interest rate of 8.4%. At inception, the Company recorded the Convertible Notes at fair value of approximately $358.1 million, a net deferred tax liability of $41.0 million and an equity component of $100.9 million.
Issuance costs were allocated to the liability and equity components of the Convertible Notes based on their relative fair values. Issuance costs attributable to the liability component of $12.1 million were recorded as a reduction to the liability component of the Convertible Notes and will be amortized to interest expense over the term of the Convertible Notes at an effective interest rate of 8.4%. Issuance costs attributable to the equity component of $4.8 million, representing the conversion option, were netted with the equity component.
The Capped Call Transactions are separate from the Convertible Notes. The Capped Call Transactions were recorded in shareholders' equity and were not accounted for as derivatives. The cost to purchase the Capped Call Transactions was recorded as a reduction to equity and will not be remeasured.
For the year ended December 31, 2020, the Convertible Notes had a net shareholders' equity impact of $63.6 million, which consisted of the conversion option equity component of $100.9 million less the Capped Call Transactions costs of $32.5 million and issuance costs attributable to the equity component of $4.8 million.
As of December 31, 2020, the net carrying amount of the Convertible Notes liability component consisted of principal of $500 million less the unamortized debt discount of $129.1 million and unamortized issuance costs of $11.3 million. The table below summarizes the components of interest expense related to the Rice Merger and related transactions including the repayment of certain indebtedness of Rice and its subsidiaries, to redeem or repay $700 million of CompanyConvertible Notes.
| | | | | |
| Year Ended December 31, 2020 |
| (Thousands) |
| Contractual interest expense | $ | 5,906 | |
| Amortization of debt discount | 12,856 | |
| Amortization of issuance costs | 853 | |
| Total Convertible Notes interest expense | $ | 19,615 | |
5.00% Senior Notes due in 2018 and for other general corporate purposes.
In October 2017,Notes. On November 16, 2020, the Company delivered redemption notices to redeem all of its outstanding $200issued $350 million aggregate principal amount 5.15% Senior Notesof 5.00% senior notes due 2018January 15, 2029. After deducting offering costs of $6.0 million, the net proceeds from the offering of $344.0 million were used to fund a portion of the purchase price of the Chevron Acquisition described in Note 6. The covenants of the 5.00% senior notes are consistent with the Company's existing senior unsecured notes; provided, however, that the 5.00% senior notes include an additional offer to repurchase provision applicable upon the occurrence of certain change of control events specified in the related indenture.
2020 Debt Repayments. In February 2020, the Company fully redeemed its floating rate notes and $500 million aggregate principal amount 6.50% Senior Notes due 2018. On November 3, 2017, the Company redeemed the 5.15% Senior Notes due 20182.50% senior notes at a redemption price of 101.252%100% and 100.446% (inclusive of a make whole premium), respectively, of each note's principal amount plus accrued but unpaid interest of $1.2 million and the 6.50% Senior Notes due 2018 at a redemption price of 101.941%, plus accrued but unpaid interest.$4.2 million, respectively. This resulted in the payment of make whole call premiums of $2.5$2.2 million related to the 2.50% senior notes.
Throughout 2020, the Company repurchased $624.9 million aggregate principal amount of the Company's 4.875% senior notes at a total cost of $647.3 million, inclusive of tender premiums of $13.7 million and $9.7accrued but unpaid interest of $8.7 million.
In November 2020, the Company repurchased $181.2 million aggregate principal amount of the Company's 3.00% senior notes at a total cost of $182.8 million, inclusive of a tender premium of $0.9 million and accrued but unpaid interest of $0.7 million.
Note Payable to EQM. EQM owns a preferred interest in EQT Energy Supply, LLC (EES), a subsidiary of the Company, that is accounted for as a note payable due to the terms of the operating agreement of EES. The fair value of the note payable to EQM is a Level 3 fair value measurement and is estimated using an income approach model using a market-based discount rate. Principal amounts due for the 5.15% Senior Notes due 2018 and the 6.50% Senior Notes due 2018, respectively. As a part of these transactions, the Company recorded loss on debt extinguishment of $12.6 million, which included the make whole call premiums and the write-off of $0.4 million in unamortized deferred financing costs.
The indentures governing the Company’s and EQM’s long-term indebtedness contain certain restrictive financial and operating covenants, including covenants that restrict, among other things, the Company’s or EQM's abilitynote payable to incur, as applicable, indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, a change in the Company’s or EQM’s debt rating would not trigger a default under the indentures governing the indebtedness.
Aggregate maturities of Senior NotesEQM are $8.0 million in 2018, $700.0 million in 2019, $1,011.2 million in 2020, $774.0$5.2 million in 2021, $750.0$5.5 million in 2022, and $2,375.0$5.8 million in 2023, $6.3 million in 2024, $6.5 million in 2025 and $75.8 million thereafter.
16.Surety Bonds. During the year ended December 31, 2020, the Company issued approximately $93 million in surety bonds in response to its credit downgrades by Moody's, S&P and Fitch.
Subsequent Events. On February 1, 2021, the Company redeemed the remaining $125.1 million aggregate principal amount of the Company's 4.875% senior notes at a total cost of $130.7 million, inclusive of redemption premiums of $4.3 million and accrued but unpaid interest of $1.3 million.
11.Common Stock
As of December 31, 2020, the Company reserved 13.7 million shares of authorized and unissued EQT common stock for stock compensation plans and 40 million shares of authorized and unissued EQT common stock for settlement of the Convertible Notes.
In October 2020, the Company entered into an underwriting agreement under which the Company sold 20,000,000 shares of common stock at a price to the public of $15.50 per share. In November 2020, the option to purchase 3,000,000 additional shares was exercised by the underwriters on the same terms. After deducting offering costs of $15.6 million, the net proceeds of $340.9 million were used to fund a portion of the purchase price of the Chevron Acquisition described in Note 6.
The Company made 0 share repurchases in 2020 or 2019. During 2018, the Company repurchased 10,646,382 shares of EQT common stock at an average price of $50.62, which included $0.02 for commission, pursuant to the Company's previously announced share repurchase programs. This exhausted the Company's share repurchase authorization under such programs.
12.Changes in Accumulated Other Comprehensive IncomeOCI (Loss) by Component
The following tables explaintable explains the changes in accumulated OCI (loss) by component for the years ended December 31, 2017, 2016, and 2015:component.
| | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas cash flow hedges,
net of tax | | Interest rate cash flow hedges,
net of tax | | Other postretirement
benefits liability adjustment, net of tax | | Accumulated
OCI (loss), net of tax |
| | (Thousands) |
| December 31, 2017 | $ | 4,625 | | | $ | (555) | | | $ | (6,528) | | | $ | (2,458) | |
| (Gains) losses reclassified from accumulated OCI, net of tax | (4,625) | | (a) | 168 | | (b) | 606 | | (c) | (3,851) | |
| Distribution to Equitrans Midstream Corporation | 0 | | | 0 | | | 903 | | | 903 | |
| December 31, 2018 | 0 | | | (387) | | | (5,019) | | | (5,406) | |
| Losses reclassified from accumulated OCI, net of tax | 0 | | | 387 | | (b) | 316 | | (c) | 703 | |
| Change in accounting principle | 0 | | | 0 | | | (496) | | | (496) | |
| December 31, 2019 | 0 | | | 0 | | | (5,199) | | | (5,199) | |
| Losses reclassified from accumulated OCI, net of tax | 0 | | | 0 | | | (156) | | (c) | (156) | |
| December 31, 2020 | $ | 0 | | | $ | 0 | | | $ | (5,355) | | | $ | (5,355) | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2017 |
| | | Natural gas cash flow hedges, net of tax | | | | Interest rate cash flow hedges, net of tax | | | | Pension and other post- retirement benefits liability adjustment, net of tax | | | | Accumulated OCI (loss), net of tax |
| | | (Thousands) |
| Accumulated OCI (loss), net of tax, as of December 31, 2016 | | $ | 9,607 |
| | | | $ | (699 | ) | | | | $ | (6,866 | ) | | | | $ | 2,042 |
|
| (Gains) losses reclassified from accumulated OCI, net of tax | | (4,982 | ) | | (a) | | 144 |
| | (a) | | 338 |
| | (b) | | (4,500 | ) |
Accumulated OCI (loss), net of tax, as of December 31, 2017 | | $ | 4,625 |
| | | | $ | (555 | ) | | | | $ | (6,528 | ) | | | | $ | (2,458 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2016 |
| | | Natural gas cash flow hedges, net of tax | | | | Interest rate cash flow hedges, net of tax | | | | Pension and other post- retirement benefits liability adjustment, net of tax | | | | Accumulated OCI (loss), net of tax |
| | | (Thousands) |
Accumulated OCI (loss), net of tax, as of December 31, 2015 | | $ | 64,762 |
| | | | $ | (843 | ) | | | | $ | (17,541 | ) | | | | $ | 46,378 |
|
| (Gains) losses reclassified from accumulated OCI, net of tax | | (55,155 | ) | | (a) | | 144 |
| | (a) | | 10,675 |
| | (b) | | (44,336 | ) |
Accumulated OCI (loss), net of tax, as of December 31, 2016 | | $ | 9,607 |
| | | | $ | (699 | ) | | | | $ | (6,866 | ) | | | | $ | 2,042 |
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2015 |
| | | Natural gas cash
flow hedges, net
of tax | | | | Interest rate
cash flow
hedges, net
of tax | | | | Pension and
other post-
retirement
benefits
liability
adjustment,
net of tax | | | | Accumulated
OCI (loss), net
of tax |
| | | (Thousands) |
Accumulated OCI (loss), net of tax, as of December 31, 2014 | | $ | 217,121 |
| | | | $ | (987 | ) | | | | $ | (16,640 | ) | | | | $ | 199,494 |
|
| (Gains) losses reclassified from accumulated OCI, net of tax | | (152,359 | ) | | (a) | | 144 |
| | (a) | | (901 | ) | | (b) | | (153,116 | ) |
Accumulated OCI (loss), net of tax, as of December 31, 2015 | | $ | 64,762 |
| | | | $ | (843 | ) | | | | $ | (17,541 | ) | | | | $ | 46,378 |
|
(a)Gains, (losses) reclassified from accumulated OCI, net of tax, related to natural gas cash flow hedges were reclassified from accumulated OCI into operating revenues.
(b)Losses, from accumulated OCI, net of tax, related to interest rate cash flow hedges were reclassified from accumulated OCI into interest expense.
(b)This accumulated OCI reclassification is(c)Losses, net of tax, related to other postretirement benefits liability adjustments were attributable to the net actuarial losslosses and net prior service costs.
13.Share-Based Compensation Plans
The following table summarizes the Company's share-based compensation expense.
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (Thousands) |
| Incentive Performance Share Unit Programs | $ | 10,457 | | | $ | 13,306 | | | $ | 14,072 | |
| Value Driver Performance Share Unit Award Programs | 885 | | | 3,376 | | | 8,808 | |
| Restricted stock awards | 10,480 | | | 14,430 | | | 14,503 | |
| Non-qualified stock options | 848 | | | 4,774 | | | 2,757 | |
| Stock appreciation rights | 2,724 | | | 0 | | | 0 | |
| Other programs, including non-employee director awards | 2,155 | | | 2,257 | | | 3,014 | |
| Less: Discontinued operations | 0 | | | 0 | | | (18,250) | |
| Total share-based compensation expense (a) | $ | 27,549 | | | $ | 38,143 | | | $ | 24,904 | |
(a)For the years ended December 31, 2020 and 2019, share-based compensation expense of $2.1 million and $28.6 million, respectively, was included in other operating expenses related primarily to reorganization costs.
In connection with the Separation in 2018, the Company transferred obligations related to then-outstanding share-based compensation awards to Equitrans Midstream. To preserve the aggregate fair value of awards held prior to the Separation, as measured immediately before and immediately after the Separation, each holder of share-based compensation awards generally received an adjusted award consisting of both a stock-based compensation award denominated in Company equity and a stock-based compensation award denominated in Equitrans Midstream equity. These awards were adjusted in accordance with the basket method, which resulted in participants retaining one unit of the existing Company incentive award and receiving an additional 0.80 units of an Equitrans Midstream-based award.
The Company recognizes compensation cost related to unvested awards held by its employees, regardless of who settles the Company’s defined benefit pension plans and other post-retirement benefit plans. See Note 1 for additional information.
17.Common Stock, Treasury Stock and Earnings Per Share
Common Stock
At December 31, 2017, shares of EQT’s authorized and unissued common stock were reserved as follows:
|
| | |
| (Thousands) |
Possible future acquisitions | 20,457 |
|
Stock compensation plans | 14,261 |
|
Total | 34,718 |
|
In conjunction with the closing of the Rice Merger,obligation. Upon vesting the Company issued approximately 91 million shares of common stock on November 13, 2017.
On February 19, 2016, the Company entered into an Underwriting Agreement with Goldman, Sachs & Co. (Goldman) under which the Company soldis obligated to Goldman 6,500,000 shares of common stock at a price to the public of $58.50 per share (the February Offering). On February 22, 2016, Goldman exercised its option within the Underwriting Agreement to purchase an additional 975,000 shares of common stock on the same terms. The February Offering closed on February 24, 2016, and the Company received net proceeds of approximately $430.4 million, after deducting underwriting discounts and commissions and offering expenses. The Company used the net proceeds from the February Offering for general corporate purposes.
On May 2, 2016, the Company entered into an Underwriting Agreement with Credit Suisse Securities (USA) LLC and J.P. Morgan Securities LLC, as representatives of the several underwriters named in the Underwriting Agreement (the Underwriters), under which the Company sold to the Underwriters 10,500,000 shares of common stock at a price to the public of $67.00 per share (the May Offering). On May 3, 2016, the Underwriters exercised their option within the Underwriting Agreement to purchase an additional 1,575,000 shares of common stock on the same terms. The May Offering closed on May 6, 2016, and the Company received net proceeds of approximately $795.6 million after deducting underwriting discounts and commissions and offering expenses. The Company used a portion of the net proceeds from the May Offering to fund the acquisitions discussed in Note 10 and the remainder for general corporate purposes.
Treasury Stock
Effective as of December 31, 2015, the Company transferred 17.0 million shares of treasury stock from issued to authorized but unissued shares. Additionally, during the year ended December 31, 2015, the Company funded 291,919 shares of treasury stock into a rabbi trust for the 2005 Directors’ Deferred Compensation Plan and the 1999 Directors' Deferred Compensation Plan. As of December 31, 2017 and 2016, there were 253,145 and 226,288 shares of treasury stock in the rabbi trust, respectively. Shares of common stock held by the rabbi trust are treated as treasury stocksettle all outstanding share-based compensation awards denominated in the Company's financial statements.
Earnings Per Share
The computationequity, regardless of basic and diluted earnings per sharewhether the holders are employees of common stock attributable to EQT Corporation is shown in the table below:
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands except per share amounts) |
| Basic earnings per common share: | | |
| | |
| | |
|
| Net income (loss) attributable to EQT Corporation | | $ | 1,508,529 |
| | $ | (452,983 | ) | | $ | 85,171 |
|
| Average common shares outstanding | | 187,380 |
| | 166,978 |
| | 152,398 |
|
| Basic earnings (loss) per common share | | $ | 8.05 |
| | $ | (2.71 | ) | | $ | 0.56 |
|
| Diluted earnings per common share: | | |
| | |
| | |
|
| Net income (loss) attributable to EQT Corporation | | $ | 1,508,529 |
| | $ | (452,983 | ) | | $ | 85,171 |
|
| Average common shares outstanding | | 187,380 |
| | 166,978 |
| | 152,398 |
|
| Potentially dilutive securities: | | |
| | |
| | |
|
| Stock options and awards (a) | | 347 |
| | — |
| | 541 |
|
| Total | | 187,727 |
| | 166,978 |
| | 152,939 |
|
| Diluted earnings (loss) per common share | | $ | 8.04 |
| | $ | (2.71 | ) | | $ | 0.56 |
|
(a)Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 429,785 shares and 291,700 shares for the years ended December 31, 2017 and 2015, respectively. In periods when the Company reports a net loss, basic and diluted earnings per common share are equal becauseor Equitrans Midstream. Likewise, upon vesting, Equitrans Midstream is obligated to settle all options and restricted stock have an anti-dilutive effect on loss per share. As a result, basic shares equaled diluted shares for the year ended December 31, 2016 because the Company was in a net loss position.
The impact of EQM’s, EQGP's, and RMP's dilutive units did not have a material impact on the Company’s earnings per share calculations for any of the periods presented.
18.Share-Based Compensation Plans
Share-basedoutstanding share-based compensation expense recordedawards denominated in its equity, regardless of whether the holders are employees of Equitrans Midstream or the Company. Changes in performance and number of outstanding awards can impact the ultimate amount of these obligations. Share counts for awards discussed herein represent outstanding shares to be remitted by the Company was as follows:
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (millions) |
| 2013 Executive Performance Incentive Program | | $ | — |
| | $ | — |
| | $ | 6.8 |
|
| 2014 Executive Performance Incentive Program | | — |
| | 9.5 |
| | 12.9 |
|
| 2015 Executive Performance Incentive Program | | 5.4 |
| | 12.4 |
| | 12.1 |
|
| 2016 Incentive Performance Share Unit Program | | 13.1 |
| | 7.2 |
| | — |
|
| 2017 Incentive Performance Share Unit Program | | 5.0 |
| | — |
| | — |
|
| 2014 EQT Value Driver Award Program | | — |
| | — |
| | 1.1 |
|
| 2014 EQM Value Driver Award Program | | — |
| | — |
| | 0.6 |
|
| 2015 EQT Value Driver Award Program | | — |
| | 3.2 |
| | 14.6 |
|
| 2016 EQT Value Driver Performance Share Unit Award Program | | 3.4 |
| | 15.7 |
| | — |
|
| 2017 EQT Value Driver Performance Share Unit Award Program | | 10.8 |
| | — |
| | — |
|
| Restricted stock awards | | 87.1 |
| | 9.4 |
| | 7.0 |
|
| Non-qualified stock options | | 2.6 |
| | 3.1 |
| | 1.9 |
|
| Other programs, including non-employee director awards | | 1.0 |
| | 5.5 |
| | (2.3 | ) |
| Total share-based compensation expense | | $ | 128.4 |
| | $ | 66.0 |
| | $ | 54.7 |
|
A portionto its employees and employees of the expense related to share-based compensation plans is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note 6.Equitrans Midstream. When an award has graduated vesting, the Company records expense equal to the vesting percentage on the vesting date.
The Company typically uses treasury stock to fund awards that are paid in stock, but the Company can elect to fund such awards may be funded by stock acquired by the Company in the open market or from any other person, issued directly by the Company or any combination of the foregoing.
CashThere was 0 cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2017, 20162020 and 20152019. Cash received from exercises under all share-based payment arrangements for employees and directors for the year ended December 31, 2018 was $0.2 million, $5.0 million and $14.0 million, respectively.$1.9 million. During the years ended December 31, 2017, 20162020, 2019 and 2015,2018, share-based payment arrangements paid in stock generated tax benefits of $58.9$1.0 million, $22.2$2.4 million and $43.1$13.4 million, respectively.
ExecutiveIncentive Performance IncentiveShare Unit Programs -– Equity & Liability
The Management Development and Compensation Committee of the Company's Board of Directors (the Compensation Committee) adopted:has adopted the:
the 2013 Executive Performance Incentive Plan (2013 Incentive PSU Program) under the 2009 Long-Term Incentive Plan (2009 LTIP);
the 2014 Executive Performance Incentive Plan (2014 Incentive PSU Program) under the 2009 LTIP;
the 2015 Executive Performance Incentive Plan (2015 Incentive PSU Program) under the 2014 Long-Term Incentive Plan (2014 LTIP);
the •2016 Incentive Performance Share Unit Program (2016 Incentive PSU Program) under the 2014 LTIP; andLong-Term Incentive Plan (LTIP);
the •2017 Incentive Performance Share Unit Program (2017 Incentive PSU Program) under the 2014 LTIP.LTIP;
•2018 Incentive Performance Share Unit Program (2018 Incentive PSU Program) under the 2014 LTIP;
•2019 Incentive Performance Share Unit Program (2019 Incentive PSU Program) under the 2014 LTIP; and
•2020 Incentive Performance Share Unit Program (2020 Incentive PSU Program) under the 2019 LTIP.
The 2013 Incentive PSU Program, the 2014 Incentive PSU Program, the 2015 Incentive PSU Program, the 2016 Incentive PSU Program and the 2017 Incentive PSU Programprograms noted above are collectively referred to as the Incentive PSU Programs. All of theThe 2016 Incentive PSU Programs with the exception of theProgram and 2020 Incentive PSU Program granted equity awards. The 2017 Incentive PSU Program, (which2018 Incentive PSU Program and 2019 Incentive PSU Program granted both equity and liability awards) granted equity awards.
The Incentive PSU Programs were established to provide long-term incentive opportunities to executives and key employees to further align their interests with those of the Company’sCompany's shareholders and with the strategic objectives of the Company. The performance period for each of the awards under the Incentive PSU Programs is 36 months, with vesting occurring upon payment following the expiration of the performance period. Awards
Executive performance incentive program awards granted were/will bein years 2016 and 2017 were earned based upon:on:
•the level of total shareholder return relative to a predefined peer group; and
with respect to the 2013 Incentive PSU Program, the level of cumulative operating cash flow per share, and with respect to the other Incentive PSU Programs, •the cumulative total sales volume growth, in each case, over the performance period.
TheExecutive performance incentive program awards granted in years 2018 and 2019 were earned based on:
•the level of total shareholder return relative to a predefined peer group;
•the level of operating and development cost improvement; and
•return on capital employed.
Beginning in 2020, executive performance incentive program awards granted are earned based on:
•adjusted well costs;
•adjusted free cash flow; and
•the level of total shareholder return relative to a predefined peer group.
Prior to 2020, the payout factor varies between zero0 and 300% of the number of outstanding units contingent upon the performance metrics listed above. The Company recorded 20132020 Incentive PSU Program has a payout factor that ranges from 0 to 150%. The Company recorded the 20142016 Incentive PSU Program, the 2015 Incentive PSU Program, the 20162020 Incentive PSU Program and the portion of the 2017 Incentive PSU Program, 2018 Incentive PSU Program and 2019 Incentive PSU Program to be settled in stock as equity awards using a grant date fair value determined through a Monte Carlo simulation, which projected the share price for the Company and its peers at the endingend point of the performance period. The 2017 Incentive PSU Program, 2018 Incentive PSU Program and 2019 Incentive PSU Program also included awards to be settled in cash, which are recorded at fair value as of the measurement date determined through a Monte Carlo simulation, which projected the share price for the Company and its peers at the endingend point of the performance period. The expected share prices were generated using each company's annual volatility for the expected term and the commensurate three-year risk-free rate shown in the chart below for equity awards and two year risk free rate shown in chart below for liability awards. below. As the Incentive PSU Programs include a performance condition that affects the number of shares that will ultimately vest, (the level of cumulative operating cash flow per share with respect to the 2013 Incentive PSU Program and the cumulative total sales volume growth performance condition with respect to the other Incentive PSU Programs), the Monte Carlo simulation computed either the grant date fair value for equity awards or the measurement date fair value for liability awards for each possible performance condition outcome on the grant date for equity awards or the measurement date for liability awards. The Company reevaluates the then-probable outcome at the end of each reporting period in order to record expense at the probable outcome grant date fair value or measurement date fair value, as applicable. The vestingVesting of the units under each Incentive PSU Program occurs upon payment after the end of the performance period. More detailed information about each award is set forth in the table below:
|
| | | | | | | | | | | | | | | | |
| Incentive PSU Program | Settled In | Accounting Treatment | Fair Value1 | Risk Free Rate | Vested/Payment Date | Awards Paid | Value (in millions) | Unvested/Expected Payment Date2 | Awards Outstanding as of December 31, 20173 |
| 2013 | Stock | Equity | $ | 140.00 |
| 0.36 | % | February 2016 | 261,073 |
| $ | 36.6 |
| N/A | N/A |
|
| 2014 | Stock | Equity | $ | 189.68 |
| 0.78 | % | February 2017 | 238,060 |
| $ | 45.2 |
| N/A | N/A |
|
| 2015 | Stock | Equity | $ | 141.11 |
| 1.10 | % | N/A | N/A |
| N/A |
| First Quarter of 2018 | 306,407 |
|
20164 | Stock | Equity | $ | 96.30 |
| 1.31 | % | N/A | N/A |
| N/A |
| First Quarter of 2019 | 447,145 |
|
20175 | Stock | Equity | $ | 120.60 |
| 1.47 | % | N/A | N/A |
| N/A |
| First Quarter of 2020 | 79,070 |
|
20176 | Cash | Liability | $ | 103.70 |
| 1.88 | % | N/A | N/A |
| N/A |
| First Quarter of 2020 | 117,530 |
|
1 Grant date fair value determined using a Monte Carlo simulation for equity awards. Fair value determined using a Monte Carlo simulation as of the measurement date for liability awards. For unvested Incentive PSU Programs the grant date fair value for equity awards and the measurement date fair value for liability awards is as of December 31, 2017. The Company recorded compensation expense as of December 31, 2017 using the grant date fair value for equity awards and the measurement date fair value for liability awards, each computed for the outcome which management estimated to be most probable.
2 Vesting of the units will occur upon payment, following the expiration of the performance period subject to continued service through such date.
3 Represents the number of outstanding units as of December 31, 2017 adjusted for forfeitures.
4 As of January 1, 2017, a total of 482,030 units were outstanding under the 2016 Incentive PSU Program. Adjusting for 34,885 forfeitures, there were 447,145 outstanding units as of December 31, 2017.
5 A total of 90,580 units were granted under the 2017 Incentive PSU Program - Equity in 2017 and no additional units may be granted. Adjusting for 11,510 forfeitures, there were 79,070 outstanding units as of December 31, 2017.
6 A total of 133,000 units were granted under the 2017 Incentive PSU Program - Liability in 2017 and no additional units may be granted. Adjusting for 15,470 forfeitures, there were 117,530 outstanding units as of December 31, 2017.
The following table sets forthsummarizes Incentive PSU Programs to be settled in stock and classified as equity awards:
| | | | | | | | | | | | | | | | | | | | |
| Incentive PSU Programs - Equity Settled | | Nonvested Shares (a) | | Weighted Average
Fair Value | | Aggregate Fair Value |
| Outstanding at January 1, 2018 | | 832,622 | | | $ | 115.10 | | | $ | 95,832,997 | |
| Granted | | 172,350 | | | 76.53 | | | 13,189,946 | |
| Vested | | (306,407) | | | 141.11 | | | (43,237,092) | |
| Forfeited | | (162,551) | | | 93.55 | | | (15,206,691) | |
| Outstanding at December 31, 2018 | | 536,014 | | | 94.36 | | | 50,579,160 | |
| Granted | | 463,380 | | | 29.45 | | | 13,646,541 | |
| Vested | | (384,101) | | | 96.30 | | | (36,988,926) | |
| Outstanding at December 31, 2019 | | 615,293 | | | 44.27 | | | 27,236,775 | |
| Granted | | 1,376,198 | | | 6.62 | | | 9,107,846 | |
| Vested | | (44,573) | | | 120.60 | | | (5,375,504) | |
| Forfeited | | (7,190) | | | 13.28 | | | (95,483) | |
Outstanding at December 31, 2020 | | 1,939,728 | | | $ | 15.92 | | | $ | 30,873,634 | |
(a)For the years ended December 31, 2020 and 2019, the Company settled total shares of 7,020 and 130,393, respectively, for Equitrans Midstream employees.
The following table summarizes Incentive PSU Programs to be settled in cash and classified as liability awards:
| | | | | | | | | | | | | | | | | | | | |
| Incentive PSU Programs - Cash Settled | | Nonvested Shares (b) | | Weighted Average
Fair Value | | Aggregate Fair Value |
| Outstanding at January 1, 2018 | | 117,530 | | | $ | 120.60 | | | $ | 14,174,118 | |
| Granted | | 142,890 | | | 76.53 | | | 10,935,371 | |
| Forfeited | | (30,582) | | | 94.56 | | | (2,891,844) | |
| Outstanding at December 31, 2018 | | 229,838 | | | 96.67 | | | 22,217,645 | |
| Granted | | 255,920 | | | 29.45 | | | 7,536,844 | |
| Forfeited | | (33,348) | | | 75.65 | | | (2,522,819) | |
| Outstanding at December 31, 2019 | | 452,410 | | | 60.19 | | | 27,231,670 | |
| Vested | | (93,359) | | | 120.60 | | | (11,259,095) | |
| Forfeited | | (19,356) | | | 61.43 | | | (1,189,050) | |
Outstanding at December 31, 2020 | | 339,695 | | | $ | 43.52 | | | $ | 14,783,525 | |
(b)For the year ended December 31, 2020, the Company settled total shares paid in cash of 40,018 for Equitrans Midstream employees.
Total capitalized compensation costs capitalized related to each of the Incentive PSU Programs:
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | (millions) |
| Award | | 2017 | | 2016 | | 2015 |
| 2013 Incentive PSU Program | | $ | — |
| | $ | — |
| | $ | 4.4 |
|
| 2014 Incentive PSU Program | | — |
| | 4.2 |
| | 4.9 |
|
| 2015 Incentive PSU Program | | 2.2 |
| | 4.9 |
| | 4.9 |
|
| 2016 Incentive PSU Program | | 4.4 |
| | 3.3 |
| | — |
|
| 2017 Incentive PSU Program (liability only) | | $ | 1.7 |
| | $ | — |
| | $ | — |
|
Programs for the years ended December 31, 2020, 2019, and 2018 were $0.9 million, $(0.8) million, and $3.7 million. As of December 31, 2017, $12.92020, $0.1 million, $6.4$0.8 million and $7.9$6.2 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 20162019 Incentive PSU Program the 2017– Equity, 2019 Incentive PSU Program - Equity– Liability and 20172020 Incentive PSU Program, - Liability, respectively, was expected to be recognized over the remainder of the performance periods.
The fairFair value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions:assumptions at grant date:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Incentive PSU Programs Issued During the Years Ended December 31, |
| 2020 (a) | | 2019 | | 2018 | | 2017 | | 2016 |
| Risk-free rate | 1.22% | | 2.44% | | 1.97% | | 1.47% | | 1.31% |
| Volatility factor | 45.41% | | 54.60% | | 32.60% | | 32.30% | | 28.43% |
| Expected term | 3 years | | 3 years | | 3 years | | 3 years | | 3 years |
|
| | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | | 2017 | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | Liability2 | | Equity |
| | Equity |
| | Equity |
| | Equity |
| | Equity |
|
| Risk-free rate | | 1.88 | % | | 1.47 | % | | 1.31 | % | | 1.10 | % | | 0.78 | % | | 0.36 | % |
Dividend Yield1 | | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
|
| Volatility factor | | 33.01 | % | | 32.30 | % | | 28.43 | % | | 27.45 | % | | 31.38 | % | | 32.97 | % |
Expected term2 | | 2 years |
| | 3 years |
| | 3 years |
| | 3 years |
| | 3 years |
| | 3 years |
|
| | | | | | | | | | | | | |
1Dividends paid from the beginning of the Performance Periodperformance period will be cumulatively added as additional shares of common stock.stock; therefore, dividend yield is not applicable.
2 Information shown
(a)There were three grant dates for the valuation of the liability plan is as of measurement date.2020 Incentive PSU Program. Amounts shown represent weighted average.
Value Driver Award Programs
The Compensation Committee has also adopted:
the 2014 Value Driver Award Program (2014 EQT VDPSU Program) under the 2009 LTIP;
the 2015 Value Driver Award Program (2015 EQT VDPSU Program) under the 2014 LTIP;
the 2016 Value Driver Performance Share Unit Award Program (2016 EQTPrograms
Historically, the Compensation Committee adopted the following programs, collectively referred to as the VDPSU Program) under the 2014 LTIP; andPrograms:
the •2017 Value Driver Performance Share Unit Award Program (2017 EQT VDPSU Program) under the 2014 LTIP.LTIP;
•2018 Value Driver Performance Share Unit Award Program (2018 EQT VDPSU Program) under the 2014 LTIP; and
•2019 Value Driver Performance Share Unit Award Program (2019 EQT VDPSU Program) under the 2014 LTIP.
The 2014 EQT VDPSU Program, the 2015 EQT VDPSU Program, the 2016 EQT VDPSU Program and the 2017 EQT VDPSU Programprograms noted above are collectively referred to as the VDPSU Programs.
The VDPSU Programs were established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. Under each VDPSU Program, 50% of the confirmed awards confirmed vestvested upon payment following the first anniversary of the grant date; the remaining 50% of the confirmed awards confirmed vestvested upon payment following the second anniversary of the grant date, subject to continued service through such date. Due to the graded vesting of each award under the VDPSU Programs, the Company recognized compensation cost over the requisite service period for each separately vesting tranche of the award as though each award was, in substance, multiple awards. The payments arewere contingent upon adjusted earnings before interest, income taxes, depreciation and amortization performance as compared to the Company's annual business plan and individual,
business unit and Company value driver performance over the respective one-year periods. MoreThe following table provides additional detailed information abouton each award is set forth in the table below:historical award.
| | | | | | | | | | | | | | |
| VDPSU Program | Accounting Treatment | Weighted Average Fair Value | Cash paid (Millions) | Awards Outstanding (including accrued dividends) as of December 31, 2020 (a) |
| 2017 | Liability | $ | 65.40 | | $ | 14.0 | | N/A |
| $ | 65.40 | | $ | 4.0 | | N/A |
| 2018 | Liability | $ | 56.92 | | $ | 4.9 | | N/A |
| $ | 56.92 | | $ | 1.2 | | N/A |
| 2019 (b) | Liability | $ | 18.89 | | $ | 1.7 | | N/A |
| $ | 18.89 | | N/A | 144,116 |
|
| | | | | | | | | | | | |
| EQT VDPSU Program | Settled In | Accounting Treatment | Fair Value per Unit1 | Vested/Payment Date | Number of awards (including accrued dividends) or cash (millions) paid | Unvested/Expected Payment Date | Awards Outstanding (including accrued dividends) as of December 31, 20172 |
| 2014 | Cash | Liability | $ | 75.70 |
| February 2015 | $ | 14.2 |
| N/A | N/A |
|
| $ | 52.13 |
| February 2016 | $ | 9.4 |
|
| 2015 | Stock | Equity | $ | 75.70 |
| February 2016 | 222,751 |
| N/A
| N/A |
|
| | | | $ | 75.70 |
| February 2017 | 208,567 |
| N/A | N/A |
|
20163 | Cash | Liability | $ | 65.40 |
| February 2017 | $ | 21.3 |
| N/A
| N/A |
|
| $ | 56.92 |
| N/A
| N/A |
| Second tranche first quarter of 2018 | 298,480 |
|
20174 | Cash | Liability | $ | 56.92 |
| N/A | N/A |
| First tranche first quarter of 2018 | 245,913 |
|
| N/A |
| N/A | N/A |
| Second tranche first quarter of 2019 | 246,297 |
|
1 For equity awards, the fair value per unit is equal to the Company's closing common stock price on the business day prior to the
grant date. For liability awards, the fair value per unit is equal to the Company's common stock price on the measurement date.
2 As of January 1,(a)The 2017 651,328 awards including accrued dividends were outstanding under the 2016 EQT VDPSU Program.Program and 2018 EQT VDPSU Program included 95,452 and 130,355 awards, respectively, for Equitrans Midstream employees that were settled by the Company.
3 In addition to the $21.3 million in awards paid in February 2017, $0.2 million in awards were paid in 2017 in accordance with employee separation agreements.
4 (b)The total liability recorded for the 20172019 EQT VDPSU Program was $21.0$1.7 million as of December 31, 2017.2020. The second tranche of the 2019 EQT VDPSU Program will be paid during the first quarter of 2021.
The following table sets forth the totalTotal capitalized compensation costs capitalized related to each of the VDPSU Programs:Programs for the years ended December 31, 2020, 2019 and 2018 were $0.4 million, $2.5 million and $3.4 million, respectively.
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | (millions) |
| Award | | 2017 | | 2016 | | 2015 |
| 2014 EQT VDPSU Program | | $ | — |
| | $ | — |
| | $ | 1.3 |
|
| 2015 EQT VDPSU Program | | — |
| | 4.1 |
| | 10.9 |
|
| 2016 EQT VDPSU Program | | 7.0 |
| | 16.3 |
| | — |
|
| 2017 EQT VDPSU Program | | $ | 10.3 |
| | $ | — |
| | $ | — |
|
Restricted Stock Unit Awards -– Equity
The Company granted 85,3501,767,960, 613,440 and 158,360145,540 restricted stock unit equity awards to key employees of the Company during the years ended December 31, 20172020, 2019 and 2016, respectively, to key employees of the Company. The restricted stock2018, respectively. Awards granted in 2019 and 2018 will be fully vestedvest at the end of the three-yearthree-year period commencing with the date of grant, assuming continued service through such date, while the 2020 awards are subject to a three-year graded vesting schedule, also assuming continued service through such date. TheFor the years ended December 31, 2020, 2019 and 2018, the weighted average fair value of these restricted stock grants, based on the grant date fair value of the Company’sEQT common stock, was approximately $63$10.02, $17.42 and $75 for the years ended December 31, 2017 and 2016,$54.33, respectively.
The Company granted 7,900 restricted stock equity awards during the year ended December 31, 2016 to its new Chief Financial Officer. The restricted shares granted were fully vested at the end of the one-year period commencing on the date of grant. The fair value of this restricted stock grant, based on the Company's closing common stock price on the grant date, was $63.33 per share.
In conjunction with the closing of the Rice Merger, the Company converted Rice restricted stock equity awards and performance share equity awards to 2,290,234 Company restricted stock equity awards on November 13, 2017. Employees who were terminated on the closing date were immediately vested in their Company awards and received Merger Consideration cash of $5.30 per Rice share. Company awards of those employees who continued employment with the Company under a transition agreement will vest upon the earlier of (i) the end of the vesting period set forth in the original award agreement or (ii) the end of such employee's employment period set forth in his/her transition agreement, in both cases subject to continued service through such date. Company awards of those employees who continued employment with the Company on an at will basis will vest in accordance with the vesting period set forth in the original award agreement, assuming continued service through such date. The fair value of these restricted stock grants, based on the grant date fair value of the Company’s common stock, was approximately $65.18 for the year December 31, 2017.
The total fair value of restricted stock awards vested during the years ended December 31, 2017, 20162020, 2019 and 20152018 was $123.0$3.2 million, $5.1$11.9 million and $3.8$39.8 million, respectively. The $123.0 million includes $13.0Total capitalized compensation costs related to the restricted stock unit equity awards was $3.0 million for the cash payment for the Merger Consideration of $5.30 per Rice share.year ended December 31, 2020.
As of December 31, 2017, $11.72020, $9.3 million of unrecognized compensation cost related to nonvested restricted stock equity awards was expected to be recognized over a remaining weighted average vesting term of approximately 1.0 year.1.1 years.
A summary ofThe following table summarizes restricted stock equity award activity as of December 31, 2017, and changes during2020.
| | | | | | | | | | | | | | | | | | | | |
| Restricted Stock - Equity Settled | | Nonvested Shares (a) | | Weighted Average
Fair Value | | Aggregate Fair Value |
Outstanding at January 1, 2020 | | 310,997 | | | $ | 25.47 | | | $ | 7,921,313 | |
| Granted | | 1,767,960 | | | 10.02 | | | 17,711,033 | |
| Vested | | (130,487) | | | 24.26 | | | (3,165,269) | |
| Forfeited | | (80,070) | | | 10.90 | | | (872,763) | |
Outstanding at December 31, 2020 | | 1,868,400 | | | $ | 11.56 | | | $ | 21,594,314 | |
(a)Nonvested shares outstanding at December 31, 2020 includes 59,340 shares for an Equitrans Midstream employee that will be settled by the year then ended, is presented below:Company.
|
| | | | | | | | | | | |
| Restricted Stock | | Non- Vested Shares | | Weighted Average Fair Value | | Aggregate Fair Value |
| Outstanding at January 1, 2017 | | 224,340 |
| | $ | 81.61 |
| | $ | 18,309,538 |
|
| Granted | | 2,375,584 |
| | 65.12 |
| | 154,690,670 |
|
| Vested | | (1,854,549 | ) | | 66.31 |
| | (122,983,162 | ) |
| Forfeited | | (15,875 | ) | | 78.12 |
| | (1,240,174 | ) |
| Outstanding at December 31, 2017 | | 729,500 |
| | $ | 66.86 |
| | $ | 48,776,872 |
|
Restricted Stock Unit Awards -– Liability
TheDuring the years ended December 31, 2019 and 2018, the Company granted 292,400686,350 and 148,860373,750 restricted stock unit liability awards, respectively, to key employees of the Company that will be paid in cash. The Company did not grant restricted stock unit awards to be paid in cash during the years ended December 31, 2017 and 2016 to key employees of the Company. Adjusting2020.
Adjusted for forfeitures, there were 386,360554,306 awards outstanding as of December 31, 2017.2020. Because these awards are liability awards, the Company records compensation expense based upon ofon the fair value of the awards as remeasured at the end of each reporting period. The restricted units granted will be fully vested at the end of the three-year period commencing with the date
of grant, assuming continued service through such date. The total liability recorded for these restricted units was $8.8$4.5 million, $4.4 million and $2.7$6.9 million as of December 31, 20172020, 2019 and December 31, 2016.2018, respectively.
Non-Qualified Stock Options
The fair value of the Company’sCompany's option grants was estimated at the dates of grant date using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the years ended December 31, 2017, 20162020, 2019 and 2015.2018. The risk-free
rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the date of grant. The dividend yield is based on the dividend yield of the Company’sEQT common stock at the time of grant. Expected volatilities are based on historical volatility of the Company’sEQT common stock. The expected term represents the period of time that options granted are expected to be outstanding based on historical option exercise experience.
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 (a) | | 2018 |
| Risk-free interest rate | 1.10 | % | | 2.48 | % | | 2.25 | % |
| Dividend yield | 0 | % | | 0.46 | % | | 0.20 | % |
| Volatility factor | 60.00 | % | | 27.97 | % | | 26.46 | % |
| Expected term | 4 years | | 5 years | | 5 years |
| Number of Options Granted | 1,000,000 | | | 779,300 | | | 287,800 | |
| Weighted Average Grant Date Fair Value | $ | 1.61 | | | $ | 5.31 | | | $ | 15.39 | |
| Total Intrinsic Value of Options Exercised (Millions) | $ | 0 | | | $ | 0 | | | $ | 0 | |
|
| | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2017 1 | | 2016 1 | | 2015 |
| Risk-free interest rate | | 1.95 | % | | 1.67 | % | | 1.61 | % |
| Dividend yield | | 0.18 | % | | 0.16 | % | | 0.12 | % |
| Volatility factor | | 27.45 | % | | 28.59 | % | | 26.80 | % |
| Expected term | | 5 years |
| | 5 years |
| | 5 years |
|
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2017 1 | | 2016 1 | | 2015 |
| Number of Options Granted | | 153,700 |
| | 228,500 |
| | 158,200 |
|
| Weighted Average Grant Date Fair Value | | $ | 17.47 |
| | $ | 15.10 |
| | $ | 19.90 |
|
| Total Intrinsic Value of Options Exercised (millions) | | $ | 1.7 |
| | $ | 3.5 |
| | $ | 15.1 |
|
1(a)There were two2 grant dates for the 2017 and 20162019 options. Amounts representAmount shown represents weighted average.
As of December 31, 2017, $2.52020, $0.8 million of unrecognized compensation cost related to outstanding nonvested stock options was expected to be recognized by December 31, 2019.2023.
A summary ofThe following table summarizes option activity as of December 31, 2017,2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-Qualified Stock Options | | Shares | | Weighted Average
Exercise Price | | Weighted Average
Remaining Contractual Term | | Aggregate Intrinsic Value |
| Outstanding at January 1, 2020 | | 2,554,729 | | | $ | 28.37 | | | | | |
| Granted | | 1,000,000 | | | 10.00 | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Outstanding at December 31, 2020 | | 3,554,729 | | | 23.20 | | | 5.3 years | | $ | 2,710,000 | |
| Exercisable at December 31, 2020 | | 2,543,829 | | | $ | 28.41 | | | 4.9 years | | $ | 0 | |
Stock Appreciation Rights
During 2020, the Company granted stock appreciation rights subject to certain performance conditions, such as adjusted well costs and changes duringadjusted free cash flow. Once vested, the year then ended,participant is presented below:
|
| | | | | | | | | | | | | |
| Non-qualified Stock Options | | Shares | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Term | | Aggregate Intrinsic Value |
| Outstanding at January 1, 2017 | | 1,174,200 |
| | $ | 60.99 |
| | | | |
| Granted | | 153,700 |
| | 63.97 |
| | | | |
| Exercised | | (158,700 | ) | | 44.84 |
| | | | |
| Forfeited | | (40,000 | ) | | 67.91 |
| | | | |
| Expired | | — |
| | — |
| | | | |
| Outstanding at December 31, 2017 | | 1,129,200 |
| | $ | 63.42 |
| | 6.25 years | | $ | 1,428,439 |
|
| Exercisable at December 31, 2017 | | 691,100 |
| | $ | 63.92 |
| | 5.08 years | | $ | 668,266 |
|
EQM Awards
Atentitled to receive, upon exercise, a number of shares of EQT’s common stock, cash or a combination of the closingtwo, based upon the excess of EQM’s IPO in July 2012, the Compensation Committee and the Boardfair market value as of Directors of EQM's general partner granted certain key Company employees performance awards under the EQM Total Return Program representing 146,490 common units of EQM. The performance condition related to the performance awards was satisfied on December 31, 2015 as the total unitholder return realized on EQM’s common units from the date of grant was at least 10%.exercise over a base price of $10.00.
The Companyawards are accounted for the EQM Total Return Programas liability awards and, as equity awards using a $20.02 grant datesuch, compensation expense is recorded based on the fair value per unit as determined using a fair value model. The model projected the unit price for EQM common units at the ending point of the performance period. The price was generated using annual historical volatilities of peer group companies for the expected term of the awards which was based uponas remeasured at the performance period.end of each reporting period using a Black-Scholes option-pricing model with the assumptions indicated in the table below. The range of expected volatilities calculated by the valuation model was 27% - 72%, and the weighted-average expected volatility was approximately 38%. Additional assumptions included the risk-free rate for the period within the contractual life of the awardsis based on the U.S. Treasury yield curve in effect at the timereporting date. The dividend yield is based on the dividend yield of grantEQT common stock at the reporting date, which is set at zero for the stock appreciation rights as the Company suspended future dividends during 2020. Expected volatilities are based on a 50-50 blend of the expected term-matched historical volatility as of the valuation date and the expected EQM distribution growth rateweighted-average implied volatility from thirty
Effective in 2014,days prior to the Compensation Committee and the Board of Directors of EQM’s general partner adopted the 2014 EQM Value Driver Award Program (2014 EQM VDPSU Program) under the 2009 LTIP and EQM’s 2012 Long-Term Incentive Plan. The 2014 EQM VDPSU Program was established to align the interests of key employees with the interests of EQM unitholders and customers and the strategic objectives of EQM. Under the 2014 EQM VDPSU Program, 50% of the units confirmed vested upon payment following the first anniversary of the grant date; the remaining 50% of the units confirmed vested upon payment following the second anniversary of the grantvaluation date. The performance metrics were EQM’s 2014 adjusted earnings before interest, income taxes, depreciation and amortization performance as compared to EQM’s annual business plan and individual, business unit and value driver performance overexpected term represents the period of January 1, 2014 throughtime between the valuation date and the midpoint of the exercise window.
| | | | | |
| 2020 Stock Appreciation Rights |
| Risk-free interest rate | 0.30 | % |
| Dividend yield | 0 | % |
| Volatility factor | 67.50 | % |
| Expected term | 3.28 years |
| Number of Stock Appreciation Rights Granted | 1,240,000 |
| Weighted Average Grant Date Fair Value | $ | 2.61 | |
| Total Intrinsic Value of Exercises (Millions) | $ | 0 | |
As of December 31, 2014. The awards vested and 31,629 awards including accrued distributions were distributed in EQM common units in February 2015 and 28,998 awards including accrued distributions were distributed in EQM common units in February 2016. EQM accounted for these awards as equity awards using the $58.79 grant date fair value per unit which was equal to EQM’s closing common unit price on the business day prior to the date2020, $4.7 million of grant. Due to the graded vesting of the awards, EQM recognizedunrecognized compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards. The total compensation cost capitalized related to the 2014 EQM VDPSU Programoutstanding stock appreciation rights was less than $0.1 million in 2015.expected to be recognized by December 31, 2022.
The following table summarizes stock appreciation rights activity as of December 31, 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock Appreciation Rights | | Shares | | Weighted Average
Exercise Price | | Weighted Average
Remaining Contractual Term | | Aggregate Intrinsic Value |
| Outstanding at January 1, 2020 | | 0 | | | $ | 0 | | | | | |
| Granted | | 1,240,000 | | | 10.00 | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Outstanding at December 31, 2020 | | 1,240,000 | | | 10.00 | | | 9.0 years | | $ | 3,360,400 | |
| Exercisable at December 31, 2020 | | 0 | | | $ | 0 | | | — | | | $ | 0 | |
Non-employee Directors’Directors' Share-Based Awards
ThePrior to 2020, the Company has historically granted to EQT non-employee directors share-based awards which vestthat vested upon grant of the awards.to non-employee directors. The share-based awards will bewere historically paid in cash or CompanyEQT common stock following the directors’a directors' termination of service on the Company’sCompany's Board of Directors. Beginning in 2020, the Company grants to non-employee directors restricted stock unit awards that vest on the date of the Company's annual meeting of shareholders immediately following the grant of such awards. The restricted stock unit awards are settled in EQT common stock on the vesting date or, if elected by the director, following a director's termination of service on the Company's Board of Directors.
Awards that willto be paid in cash are accounted for as liability awards and, as such, compensation expense is recorded based uponon the fair value of the awards as remeasured at the end of each reporting period. Awards that willto be settled in CompanyEQT common stock are accounted for as equity awards and, as such, the Company recorded compensation expense foris recorded based on the fair value of the awards at the grant date fair value. A total of 217,414398,456 non-employee director share-based awards, including accrued dividends, were outstanding as of December 31, 2017.2020. A total of 26,090, 37,620201,300, 146,790 and 24,11050,979 share-based awards were granted to non-employee directors during the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively. The weighted average fair value of these grants, based on the Company’s closing EQT common stock price on the business day prior to the grant date, was $65.35, $52.13$13.46, $18.11 and $75.52$52.65 for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively.
The general partner of EQM has granted EQM common unit-based phantom awards to its independent directors, which vested upon grant. The value ofSubsequent Events - 2021 Awards
Effective in 2021, the phantom awards will be paid in EQM common units uponCompensation Committee adopted the director’s termination of service on the general partner’s Board of Directors. The Company accounts for these awards as equity awards and as such recorded compensation expense for the fair value of the awards at the grant date fair value. A total of 21,740 independent director unit-based awards including accrued distributions were outstanding as of December 31, 2017. A total of 2,940, 2,610 and 2,220 unit-based awards were granted to independent directors during the years ended December 31, 2017, 2016 and 2015, respectively. The weighted average fair value of these grants, based on EQM’s closing common unit price on the business day prior to the grant date, was $76.68, $75.46 and $88.00 for the years ended December 31, 2017, 2016 and 2015, respectively.
The general partner of EQGP has granted EQGP common unit-based phantom awards to its independent directors, which vested upon grant. The value of the phantom awards will be paid in EQGP common units upon the director’s termination of service on the general partner’s Board of Directors. The Company accounts for these awards as equity awards and as such recorded compensation expense for the fair value of the awards at the grant date fair value. A total of 21,014 independent director unit-based awards including accrued distributions were outstanding as of December 31, 2017. A total of 8,940, 8,270 and 2,910 unit-based awards were granted to independent directors during the years ended December 31, 2017, 2016 and 2015, respectively. The weighted average fair value of these grants, based on EQGP’s closing common unit price on the business day prior to the grant date, was $25.21, $21.57, and $28.77 for the years ended December 31, 2017, 2016, and 2015 respectively.
The general partner of RMP has granted RMP common unit-based awards to certain of its independent directors, which vest one year from the date of grant, contingent upon continued service through such date. The Company records these awards as equity awards. A total of 20,688 independent director unit-based awards including accrued distributions were outstanding as of December 31, 2017. A total of 20,688 unit based awards were granted to independent directors during the year ended December 31, 2017. The fair value of these grants, based on RMP’s closing common unit price on the business day prior to the grant date, was $24.41 for the year ended December 31, 2017. There have been no unit-based awards granted to independent directors since the Rice Merger.
2018 Value Driver Performance Share Unit Award Program and 20182021 Incentive Performance Share Unit Program
Effective in 2018, the Compensation Committee adopted the 2018 EQT Value Driver Performance Share Unit Award Program (2018 EQT VDPSU Program) and the 2018 Incentive Performance Share Unit Program (2018 (2021 Incentive PSU Program)
under the 20142020 LTIP. The 2018 EQT VDPSU Program and 20182021 Incentive PSU Program werewas established to align the interests of executives and key employees with the interests of shareholders and customers and the strategic objectives of the Company.
A total of 363,460922,260 units were granted under the 2018 EQT VDPSU Program. Fifty percent of the units confirmed under the 2018 EQT VDPSU will vest upon payment following the first anniversary of the grant date; the remaining 50% of the confirmed units under the 2018 EQT VDPSU Program will vest upon payment following the second anniversary of the grant date. The payout will vary between zero and 300% of the number of outstanding units contingent upon adjusted 2018 earnings before interest, income taxes, depreciation and amortization performance as compared to the Company’s annual business plan and individual, business unit and Company value driver performance over the period January 1, 2018 through December 31, 2018. If earned, the 2018 EQT VDPSU Program units are expected to be paid in cash.
A total of 314,210 units were granted under the 20182021 Incentive PSU Program. The vestingpayout of the stock units under the 2018 Incentive PSU Program will occur upon payment after December 31, 2020 (the end of the three-year performance period). The payout will vary between zero0 and 300%200% of the number of outstanding units contingent upon a combination of the level ofCompany's absolute total shareholder return and total shareholder return relative to a predefined peer group the level of operating and development cost improvement, and return on capital employed over the period January 1, 20182021 through December 31, 2020. For certain key employees, the award will be reduced if the first year synergies in connection with the Rice Merger are not achieved. If earned, 172,350 of the 2018 Incentive PSU Program units are expected to be distributed in Company common stock and 141,860 of the 2018 Incentive PSU Program units are expected to be paid in cash. 2023.
2018 Stock Options
Effective January 1, 2018,in 2021, the Compensation Committee granted 287,800 non-qualified stock options to key employees of the Company. The 2018 options are ten-year options, with an exercise price of $56.92, and are subject to three-year cliff vesting.
2018 Restricted Stock and Restricted Stock Unit Awards
Effective January 1, 2018, the Compensation Committee granted 86,200 restricted stock equity and 264,930 restricted stock unit liability awards. The1,889,510 restricted stock equity awards and restricted stock unit liability awardsthat will be fully vested at the end of thefollow a three-year periodgraded vesting schedule commencing with the date of grant, assuming continued employment. The share total includes the newly instituted "equity-for-all" program, which granted equity awards to all permanent full-time employees beginning in 2021.
19.
14.Concentrations of Credit Risk
Revenues and related accounts receivable from the EQT Production segment’sCompany's operations are generated primarily from the sale of produced natural gas, NGLs and crude oil to marketers, utilityutilities and industrial customers located mainly in the Appalachian Basin and in markets availablethat are accessible through the Company's current transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States.States and Canada. The Company also contracts with certain processors to market a portion of NGLs on behalf of the Company. Additionally, a significant amountWe do not depend on any single customer and believe that the loss of revenues and related accounts receivable from EQM Gathering, EQM Transmission and RMP Gathering are generated from the transportation ofany one customer would not have an adverse effect on our ability to sell our natural gas, in PennsylvaniaNGLs and West Virginia. No single customer accounted for more than 10%oil.
Approximately 86% and 62% of the Company's revenues for 2017 and 2016. One customer within the EQT Production segment accounted for approximately 10% of the Company's total operating revenues in 2015.
Approximately 59% and 68% of the Company’s accounts receivable balancebalances as of December 31, 20172020 and 2016,2019, respectively, representedrepresent amounts due from marketers.non-end users. The Company manages the credit risk of sales to marketersnon-end users by limiting its dealings to those marketerswith only non-end users that meet the Company’sCompany's criteria for credit and liquidity strength and by regularly monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in ordernon-end user for that marketernon-end user to meet the Company’sCompany's credit criteria. As a result, theThe Company did not experience any significant defaults on sales of natural gas to marketersnon-end users during the years ended December 31, 2017, 20162020, 2019 or 2015.2018.
The Company is exposed to credit loss in the event of nonperformance by counterparties to its derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company’sCompany's OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as thatthe financial industry as a whole.
The Company utilizesuses various processes and analyses to monitor and evaluate its credit risk exposures. These includeexposures, including monitoring current market conditions and counterparty credit fundamentals and credit default swap rates.fundamentals. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enters into transactions primarily with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.
As of December 31, 2017,2020, the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to its derivative contracts. During the year ended December 31, 2017,2020, the Company made no0 adjustments to the fair value of its derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company’sCompany's established fair value procedure. The Company monitors market conditions that may impact the fair value of its derivative contracts reportedcontracts.
15.Leases
The Company primarily leases drilling rigs, other drilling equipment and facilities.
On January 1, 2019, in connection with the Company's adoption of ASU 2016-02, Leases, the Company recorded in its Consolidated Balance Sheet $89.0 million of right-of-use assets and lease liabilities representing the present value of the Company's right to use its leased assets and obligation to make lease payments on those leased assets, respectively.
To determine the present value of its right-of-use assets and lease liabilities at adoption and thereafter, the Company calculates a discount rate per lease contract based on an estimate of the rate of interest that the Company would pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payment obligation.
Upon adoption of ASU 2016-02, the Company elected a practical expedient to forgo application of the recognition requirements under the standard to short-term leases; as such, short-term leases are not recorded in the Consolidated Balance Sheets. In addition, the Company elected a practical expedient to account for lease and nonlease components together as a lease.
Certain of the Company's lease contracts include variable lease payments, such as property taxes, other operating and maintenance expenses and payments based on asset use, which are not included in operating lease cost or the present value of the right-of-use asset or lease liability. Certain of the Company's lease contracts provide renewal periods at the Company's option; if a renewal period option is reasonably assured to be exercised, the associated lease payment obligations are included in the present value of the right-of-use asset and lease liability. As of December 31, 2020 and 2019, the Company was not a lessor. 20.
The following table summarizes the Company's lease costs.
| | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | | 2019 |
| (Thousands) |
| Operating lease costs | $ | 28,286 | | | $ | 57,517 | |
| Variable lease costs (a) | 15,922 | | | 17,143 | |
| Total lease costs (b) | $ | 44,208 | | | $ | 74,660 | |
(a)Includes short-term lease costs.
(b)For the years ended December 31, 2020 and 2019, includes drilling rig lease costs capitalized to property, plant and equipment of $29.9 million and $58.5 million, respectively, of which $19.9 million and $48.1 million, respectively, were operating lease costs.
During the fourth quarter of 2020, the Company recognized $22.8 million of right-of-use asset impairment in impairment of intangible and other assets in the Statement of Consolidated Operations as a result of the Company's assessment that the fair values of certain of the Company's right-of-use assets were less than their carrying values.
For the years ended December 31, 2020 and 2019, cash paid for lease liabilities and reported in cash flows provided by operating activities in the Statements of Consolidated Cash Flows was $10.4 million and $10.8 million, respectively. During the years ended December 31, 2020 and 2019, the Company recorded $18.9 million and $24.3 million, respectively, of right-of-use assets in exchange for new lease liabilities.
The Company records its right-of-use assets in other assets and the current and noncurrent portions of its lease liabilities in other current liabilities and other liabilities and credits, respectively, in the Consolidated Balance Sheets. As of December 31, 2020 and 2019, right-of-use assets were $21.6 million and $52.2 million, respectively, and lease liabilities were $49.9 million and $59.0 million, respectively, of which $25.0 million and $29.0 million, respectively, were classified as current. As of December 31, 2020 and 2019, the weighted average remaining lease term was 2.8 years and 3.3 years, respectively. As of both December 31, 2020 and 2019, the weighted average discount rate was 3.3%.
The following table summarizes the Company's lease payment obligations as of December 31, 2020.
| | | | | |
| December 31, 2020 |
| (Thousands) |
| 2021 | $ | 26,197 | |
| 2022 | 9,841 | |
| 2023 | 9,764 | |
| 2024 | 6,456 | |
| 2025 | 150 | |
| |
| Total lease payment obligations | 52,408 | |
| Less: Interest | 2,495 | |
| Present value of lease liabilities | $ | 49,913 | |
16.Commitments and Contingencies
The Company has commitments for demand charges under existing long-term contracts and binding precedent agreements with various unconsolidated pipelines as well as commitments with third parties for processing capacity. FutureAggregate future payments for these items as of December 31, 2017 totaled $16.42020 were $24.8 billion, (2018 - $652.7 million, 2019 - $1,022.2 million, 2020 - $1,007.5 million,composed of $1.3 billion in 2021, - $1,004.2 million,$1.7 billion in 2022, - $1,000.5 million$1.8 billion in 2023, $1.9 billion in 2024, $1.8 billion in 2025 and thereafter - $11.7 billion).$16.3 billion thereafter. The Company also has entered into agreementscommitments to release some of its capacity to various third parties. The Company's commitments for demand charges under existing long-term contracts and binding precedent agreements with EQM totaled $5.6 billion as of December 31, 2017.
The Company has agreements with drilling contractors to provide drillingpurchase equipment, and services to the Company. These obligations totaled approximately $92.3 million as of December 31, 2017. Operating lease rentals for drilling contractors, office locations and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $60.8 million in 2017, $44.1 million in 2016 and $85.2 million in 2015. Future lease payments under non-cancelable operating leases as of December 31, 2017 totaled $231.5 million (2018 - $70.9 million, 2019 - $51.3 million, 2020 - $13.4 million, 2021 – $13.6 million, 2022 - $13.6 million and thereafter - $68.7 million).
RMP is party to a water system expansion and supply agreement with an affiliate of the Company and Southwestern Pennsylvania Water Authority (SPWA) pursuant to which the Company and RMP have agreed to jointly fund and assist SPWA in the construction and expansion of its water supply system serving parts of Greene, Fayette and Washington Counties in Pennsylvania. To date, RMP has executed authorizations for expenditures totaling approximately $29.5 million, and have funded approximately $9.7 million during the year ended 2017. In exchange for the Company and RMP’s agreement to fund this construction and expansion, SPWA granted to the Company and RMP preferred rights to water volumes supplied through the systemmaterials, frac sand for use in the Company and RMP’s oil and gas operations. Additionally, the Company and RMP are entitled to receive a surcharge assessed by SPWA against all oil and gas customers to whom water is supplied through the system in an amount equal to $3.50 per 1,000 gallons of water sold. All facilities and improvements constructed pursuant to the agreement are the property of SPWA.
Commencing in January 2017, the Company has commitments for frac sand to be used as a proppant in its hydraulic fracturing operations. Futureoperations and minimum volume commitments associated with certain water agreements. As of December 31, 2020, future commitments under these contracts were $96.5 million in 2021 and $14.3 million in 2022.
See Note 15 for a summary of undiscounted future cash flows owed by the Company as lessee to lessors pursuant to contractual agreements in effect as of December 31, 2017 totaled $30.6 million (2018 - $15.2 million2020.
Conditioned upon the credit ratings assigned by Moody's, S&P and 2019 - $15.4 million).
If any credit rating agency downgradesFitch to the Company's or EQM's ratings, particularly below investment grade, the Company or EQM may be required to provide additional credit assurances in support of commercial agreements, such as pipeline capacity contracts, joint venture arrangements and subsidiary construction contracts, the amount of which may be substantial.
Priorsenior notes, counterparties to the Rice Merger, Rice entered into a Development AgreementCompany's derivative and Area of Mutual Interest Agreement (collectively, the Utica Development Agreements) with the minority interest owner in Strike Force Midstream, covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. Pursuant to the Utica Development Agreements, the Company had approximately 68.7% participating interest in acreage currently owned or to be acquired by the Company or the minority interest owner in Strike Force Midstream located within Goshen and Smith Townships (the Northern Contract Area) and an approximately 48.2% participating interest in acreage currently owned or to be acquired by the Company or the minority interest owner in Strike Force Midstream located within Wayne and Washington Townships (the Southern Contract Area), all within Belmont County, Ohio. The majority of the remaining participating interests are held by the minority interest owner in Strike Force Midstream. The participating interestsmidstream services contracts may request additional assurances of the Company, including collateral. See Note 3 for a discussion of what is deemed investment grade and the minority interest owner in Strike Force Midstream in each of the Northern and Southern Contract Areas approximated the Company’s then-current relative acreage positions in each area.
Pursuant to the Development Agreement, the Company is named the operator of drilling units located in the Northern Contract Area and the minority interest owner in Strike Force Midstream is named the operator of drilling units located in the Southern Contract Area. Upon development of a wellother factors affecting margin deposit requirements on the subject acreage, the Company and the minority interest owner in Strike Force Midstream will convey to one another, pursuant to a cross conveyance, a working interest percentage equal to the amount
The Utica Development Agreements have terms of 10 years and are terminable upon 90 days’ notice by either party; provided that, with respect to interests included within a drilling unit, such interests shall remain subject to the applicable joint operating agreement and the Company and the minority interest owner in Strike Force Midstream shall remain operators of drilling units located in the Northern and Southern Contract Areas, respectively, following such termination.
The Company is subject to various federal, state and local environmental and environmentally-related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in the assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferredCompany's derivative contracts as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company’s financial position, results of operations or liquidity. The Company has identified situations that require remedial action for which approximately $11.2 million is included in other liabilities and credits in the Consolidated Balance Sheetswell as collateral posted as of December 31, 2017.2020. See Note 10 for a discussion of letters of credit outstanding and surety bonds posted as of December 31, 2020.
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal orand other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.
The Company is subject to various federal, state and local environmental and environmentally-related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may result in the assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company's financial position, results of operations or liquidity. The Company has identified situations that require remedial action for which approximately $18.9 million was recorded in other liabilities and credits in the Consolidated Balance Sheet as of December 31, 2020. 21.
17.Guarantees
In connection with the sale of its NORESCO domestic operations in December 2005, the Company agreed to maintain in placein-place guarantees of certain warranty obligations of NORESCO. The savings guarantees provided that, once thean energy-efficiency construction project was completed by NORESCO, the customer would experience a certain dollar amount of energy savings over a periodnumber of years. The undiscounted maximum aggregate payments that may be due related to these guarantees were approximately $95$44 million as of December 31, 2017,2020, extending at a decreasing amount for approximately 118 years.
See Note 12 for discussion ofThis guarantee is exempt from ASC Topic 460, Guarantees. The Company considers the MVP Joint Venture guarantee.
22. Interim Financial Information (Unaudited)
The following quarterly summary of operating results reflects variations due primarilylikelihood that it will be required to perform on these arrangements to be remote and expects any potential payments to be immaterial to the impactCompany's financial position, results of Tax Reform Legislationoperations and liquidity. As such, the Company has not recorded any liabilities related to this guarantee in the three months ended December 31, 2017, the volatility of natural gas commodity prices, including recognition of impairment expense on long-lived assets, and the seasonal nature of the Company’s transmission, storage and marketing businesses. The summary also reflects the operations of Rice for the period of November 13, 2017 through December 31, 2017 due to the closing of the Rice Merger on November 13, 2017.its Consolidated Balance Sheets.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended |
| | | March 31 | | June 30 | | September 30 | | December 31 |
| | | (Thousands, except per share amounts) |
| 2017 (a) | | |
| | |
| | |
| | |
|
| Total operating revenues | | $ | 897,523 |
| | $ | 690,893 |
| | $ | 660,313 |
| | $ | 1,129,286 |
|
| Operating income | | 390,644 |
| | 189,794 |
| | 137,694 |
| | 214,849 |
|
| Net income | | 250,705 |
| | 122,645 |
| | 105,457 |
| | 1,379,335 |
|
| Net income attributable to EQT Corporation | | 163,992 |
| | 41,126 |
| | 23,340 |
| | 1,280,071 |
|
| Earnings per share of common stock attributable to EQT Corporation: | | |
| | |
| | |
| | |
|
| Basic: | | |
| | |
| | |
| | |
|
| Net income | | $ | 0.95 |
| | $ | 0.24 |
| | $ | 0.13 |
| | $ | 5.85 |
|
| Diluted: | | | | | | | | |
|
| Net income | | $ | 0.95 |
| | $ | 0.24 |
| | $ | 0.13 |
| | $ | 5.83 |
|
| 2016 (a) | | |
| | |
| | |
| | |
|
| Total operating revenues | | $ | 545,069 |
| | $ | 127,531 |
| | $ | 556,726 |
| | $ | 379,022 |
|
| Operating income | | 127,201 |
| | (324,492 | ) | | 108,457 |
| | (189,466 | ) |
| Net income (loss) | | 88,425 |
| | (180,807 | ) | | 70,104 |
| | (108,785 | ) |
| Net income (loss) attributable to EQT Corporation | | 5,636 |
| | (258,645 | ) | | (8,016 | ) | | (191,958 | ) |
| Earnings per share of common stock attributable to EQT Corporation: | | |
| | |
| | |
| | |
|
| Basic: | | |
| | |
| | |
| | |
|
| Net income (loss) | | $ | 0.04 |
| | $ | (1.55 | ) | | $ | (0.05 | ) | | $ | (1.11 | ) |
| Diluted: | | |
| | |
| | |
| | |
|
| Net income (loss) | | $ | 0.04 |
| | $ | (1.55 | ) | | $ | (0.05 | ) | | $ | (1.11 | ) |
23. 18.Natural Gas Producing Activities (Unaudited)
The following supplementary information summarized below presents the results of natural gas and oil activities for the EQT Production segment in accordance with the successful efforts method of accounting for production activities.
Production Costs
The following tables present the total aggregate capitalized costs and the costs incurred relatingrelated to natural gas, NGLs and oil production activities (a):activities.
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (Thousands) |
| Capitalized costs | | | | | |
| Proved properties | $ | 19,479,211 | | | $ | 17,994,820 | | | $ | 17,648,731 | |
| Unproved properties | 2,291,814 | | | 3,322,014 | | | 4,166,048 | |
| Total capitalized costs | 21,771,025 | | | 21,316,834 | | | 21,814,779 | |
| Less: Accumulated depreciation and depletion | 5,866,418 | | | 5,402,515 | | | 4,666,212 | |
| Net capitalized costs | $ | 15,904,607 | | | $ | 15,914,319 | | | $ | 17,148,567 | |
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| At December 31: | | |
| | |
| | |
|
| Capitalized Costs: | | | | | | |
| Proved properties | | $ | 18,920,855 |
| | $ | 12,179,833 |
| | $ | 10,918,499 |
|
| Unproved properties | | 5,016,299 |
| | 1,698,826 |
| | 898,270 |
|
| Total capitalized costs | | 23,937,154 |
| | 13,878,659 |
| | 11,816,769 |
|
| Accumulated depreciation and depletion | | 5,121,646 |
| | 4,217,154 |
| | 3,425,618 |
|
| Net capitalized costs | | $ | 18,815,508 |
| | $ | 9,661,505 |
| | $ | 8,391,151 |
|
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | | 2019 | | 2018 |
| (Thousands) |
| Costs incurred (a) | | | | | |
| Property acquisition: | | | | | |
| Proved properties (b) | $ | 761,940 | | | $ | 40,316 | | | $ | 77,099 | |
| Unproved properties (c) | 78,404 | | | 154,128 | | | 198,854 | |
| Exploration | 5,484 | | | 7,223 | | | 1,708 | |
| Development | 947,233 | | | 1,560,346 | | | 2,443,980 | |
| | | | | |
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Costs incurred: (a) | | | | | | |
| Property acquisition: | | |
| | |
| | |
|
| Proved properties (b) | | $ | 5,251,711 |
| | $ | 403,314 |
| | $ | 23,890 |
|
| Unproved properties (c) | | 3,310,995 |
| | 880,545 |
| | 158,405 |
|
| Exploration (d) | | 15,505 |
| | 6,047 |
| | 53,463 |
|
| Development | | 1,365,615 |
| | 777,787 |
| | 1,633,498 |
|
| Geological and geophysical | | — |
| | — |
| | — |
|
(a)Amounts exclude capital expenditures for facilities, information technology and information technology.other corporate items.
(b)Amounts in 20172020 include $2,530.4$674.0 million and $1,192.0$6.5 million for the purchase of Marcellus and Utica wells, and leases, respectively, acquired inassociated with the 2017 transactions discussed in Notes 2 and 10. The purchase of Marcellus leases includes measurement period adjustments to the 2016 acquisitions.Chevron Acquisition. Amounts in 2017 also2018 include $1,228.6$5.2 million and $0.3 million for the purchase of Utica wells and leases, respectively, acquired in the 2017 transactions discussed in Notes 2 and 10. Amounts in 2016 include $256.2 million and $112.2$9.2 million for the purchase of Marcellus and Utica wells, and leases, respectively, acquired inincluding the 2016 transactions discussed in Note 10.impact of measurement period adjustments for 2017 acquisitions.
(c)Amounts in 20172020 include $2,625.1 million and $0.5$38.9 million for the purchase of Marcellus leases and Utica leases, respectively, acquired inunproved properties associated with the 2017 transactions discussed in Notes 2 and 10. Amounts in 2016 include $770.4 million for the purchase of Marcellus leases acquired in the 2016 transactions discussed in Note 10.Chevron Acquisition.
(d)Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.
Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis. Indicators of potential impairment include changes in development plans resulting from economic factors, potential shifts in business strategy employed by management and historical experience. If it is determined that the properties will not yield proved reserves prior to the expiration or abandonment of the lease, the related costs are expensed in the period in which that determination is made. For the year ended December 31, 2017, EQT Production recorded no unproved property impairment. For the years ended December 31, 2016 and 2015, the Company recorded unproved property impairments of $6.9 million and $19.7 million, respectively, which are included in the impairment of long-lived assets in the Statements of Consolidated Operations. In addition, non-cash charges for leases which expired prior to drilling of $7.6 million, $8.7 million and $37.4 million are included in exploration
expense for the years ended December 31, 2017, 2016 and 2015, respectively. Unproved properties had a net book value of $5,016.3 million and $1,698.8 million at December 31, 2017 and 2016, respectively.
Results of Operations for Producing Activities
The following table presents the results of operations related to natural gas, NGLs and oil production:production.
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (Thousands) |
| Sales of natural gas, NGLs and oil | $ | 2,650,299 | | | $ | 3,791,414 | | | $ | 4,695,519 | |
| Transportation and processing | 1,710,734 | | | 1,752,752 | | | 1,697,001 | |
| Production | 155,403 | | | 153,785 | | | 195,775 | |
| Exploration | 5,484 | | | 7,223 | | | 6,765 | |
| Depreciation and depletion | 1,393,465 | | | 1,538,745 | | | 1,569,038 | |
| Impairment/loss on sale/exchange of long-lived assets | 100,729 | | | 1,138,287 | | | 2,709,976 | |
| Impairment and expiration of leases | 306,688 | | | 556,424 | | | 279,708 | |
| Income tax benefit | (254,671) | | | (340,843) | | | (454,009) | |
| Results of operations from producing activities, excluding corporate overhead | $ | (767,533) | | | $ | (1,014,959) | | | $ | (1,308,735) | |
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Revenues: | | |
| | |
| | |
|
| Nonaffiliated | | $ | 2,651,318 |
| | $ | 1,594,997 |
| | $ | 1,690,360 |
|
| Production costs | | 1,338,069 |
| | 1,055,017 |
| | 877,194 |
|
| Exploration costs | | 25,117 |
| | 13,410 |
| | 61,970 |
|
| Depreciation, depletion and accretion | | 982,103 |
| | 859,018 |
| | 765,298 |
|
| Impairment of long-lived assets | | — |
| | 6,939 |
| | 122,469 |
|
| Amortization of intangible assets | | 5,540 |
| | — |
| | — |
|
| Income tax expense (benefit) | | 117,984 |
| | (136,323 | ) | | (54,857 | ) |
| Results of operations from producing activities (excluding corporate overhead) | | $ | 182,505 |
| | $ | (203,064 | ) | | $ | (81,714 | ) |
Reserve Information
Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.
The information presented below represents estimatesCompany's estimate of proved natural gas, NGLs and crude oil reserves was prepared by Company engineers. The engineer primarily responsible for preparingoverseeing the reserve report and the technical aspectspreparation of the reserves audit receivedestimate holds a bachelor’sbachelor's degree in Petroleum and Natural Gas Engineeringchemical engineering from the PennsylvaniaMichigan Technological University, a master's degree in chemical engineering from Colorado State University and an executive master of business administration in energy from the University of Oklahoma and has 2920 years of experience in the oil and gas industry. To ensure thatsupport the reserves are materially accurate management reviewsand timely preparation and disclosure of its reserve estimates, the Company established internal controls over its reserve estimation processes and procedures, including the following: the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves;reserves are reviewed by management; division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reservereserves reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGLs and crude oil reserves are audited by theNetherland, Sewell & Associates, Inc. (NSAI), an independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott), which is hired by the Company’s management. Since 1937, Ryder Scott1961, NSAI has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.
Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. There were no differences between the internally prepared and externally audited estimates. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. In the course of its audit, Ryder Scott reviewedNSAI conducted a detailed review of 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company’sCompany's interests as of December 31, 2017. Ryder Scott2020. NSAI conducted a detailed, well by well,well-by-well audit of all the Company’s largest
Company's properties. This audit covered 81% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining 19% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 256 wells per case for non-operated wells. For undeveloped locations,The estimates prepared by the Company determined, and Ryder Scott reviewed and approved, the areasaudited by NSAI were within the Company’s acreage consideredrecommended 10% tolerance threshold set forth in the Standards Pertaining to be proven.the Estimating and Auditing of Oil and Gas Reserves were assigned and projectedInformation promulgated by the Company’s reserve engineers for locations within these proven areasSociety of Petroleum Engineers (SPE Standards). Standard engineering and approved by Ryder Scott based on analogous type curvesgeoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy and offset production information. The auditmaterial balance were utilized in the performance method and the analogy method. Where historical reserve or production data was definitive, the performance method, which extrapolates historical data, was utilized. In other cases the analogy method, which calculates reserves based on correlations to comparable surrounding wells, was utilized.evaluation of reserves. All of the Company’sCompany's proved reserves are located in the United States.
|
| | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Millions of Cubic Feet) |
| Total - Natural Gas, Oil, and NGLs (a) | | |
| | |
| | |
|
| Proved developed and undeveloped reserves: | | |
| | |
| | |
|
| Beginning of year | | 13,508,407 |
| | 9,976,597 |
| | 10,738,948 |
|
| Revision of previous estimates | | (2,766,981 | ) | | (472,285 | ) | | (2,194,675 | ) |
| Purchase of hydrocarbons in place | | 9,389,638 |
| | 2,395,776 |
| | — |
|
| Sale of hydrocarbons in place | | (2,646 | ) | | — |
| | (61 | ) |
| Extensions, discoveries and other additions | | 2,225,141 |
| | 2,384,682 |
| | 2,051,071 |
|
| Production | | (907,892 | ) | | (776,363 | ) | | (618,686 | ) |
| End of year | | 21,445,667 |
| | 13,508,407 |
| | 9,976,597 |
|
| Proved developed reserves: | | |
| | |
| | |
|
| Beginning of year | | 6,842,958 |
| | 6,279,557 |
| | 4,826,387 |
|
| End of year | | 11,297,956 |
| | 6,842,958 |
| | 6,279,557 |
|
| Proved undeveloped reserves: | | | | | | |
| Beginning of year | | 6,665,449 |
| | 3,697,040 |
| | 5,912,561 |
|
| End of year | | 10,147,711 |
| | 6,665,449 |
| | 3,697,040 |
|
(a) OilFor all tables presented, NGLs and NGLsoil were converted at thea rate of one thousand Bbl equalMbbl to approximately 6 million cubic feet (MMcf).
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (MMcf) |
| Natural gas, NGLs and oil | | | | | |
| Proved developed and undeveloped reserves: | | | | | |
| Balance at January 1 | 17,469,394 | | | 21,816,776 | | | 21,445,667 | |
| Revision of previous estimates | (739,213) | | | (4,907,239) | | | (1,124,904) | |
| Purchase of hydrocarbons in place | 1,380,564 | | | 0 | | | 0 | |
| Sale of hydrocarbons in place | (256,663) | | | 0 | | | (1,748,557) | |
| Extensions, discoveries and other additions | 3,445,802 | | | 2,067,753 | | | 4,739,233 | |
| Production | (1,497,792) | | | (1,507,896) | | | (1,494,663) | |
| Balance at December 31 | 19,802,092 | | | 17,469,394 | | | 21,816,776 | |
| Proved developed reserves: | | | | | |
| Balance at January 1 | 12,443,987 | | | 11,550,161 | | | 11,297,956 | |
| Balance at December 31 | 13,641,345 | | | 12,443,987 | | | 11,550,161 | |
| Proved undeveloped reserves: | | | | | |
| Balance at January 1 | 5,025,407 | | | 10,266,615 | | | 10,147,711 | |
| Balance at December 31 | 6,160,747 | | | 5,025,407 | | | 10,266,615 | |
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (MMcf) |
| Natural gas | | | | | |
| Proved developed and undeveloped reserves: | | | | | |
| Balance at January 1 | 16,677,202 | | | 20,805,452 | | | 19,830,236 | |
| Revision of previous estimates | (781,668) | | | (4,722,799) | | | (960,285) | |
| Purchase of natural gas in place | 1,209,326 | | | 0 | | | 0 | |
| Sale of natural gas in place | (254,930) | | | 0 | | | (1,331,391) | |
| Extensions, discoveries and other additions | 3,433,857 | | | 2,029,683 | | | 4,659,835 | |
| Production | (1,418,774) | | | (1,435,134) | | | (1,392,943) | |
| Balance at December 31 | 18,865,013 | | | 16,677,202 | | | 20,805,452 | |
| Proved developed reserves: | | | | | |
| Balance at January 1 | 11,811,521 | | | 10,887,953 | | | 10,152,543 | |
| Balance at December 31 | 12,750,312 | | | 11,811,521 | | | 10,887,953 | |
| Proved undeveloped reserves: | | | | | |
| Balance at January 1 | 4,865,681 | | | 9,917,499 | | | 9,677,693 | |
| Balance at December 31 | 6,114,701 | | | 4,865,681 | | | 9,917,499 | |
|
| | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Millions of Cubic Feet) |
| Natural Gas | | |
| | |
| | |
|
| Proved developed and undeveloped reserves: | | |
| | |
| | |
|
| Beginning of year | | 12,331,867 |
| | 9,110,311 |
| | 9,775,954 |
|
| Revision of previous estimates | | (2,760,467 | ) | | (607,171 | ) | | (2,059,531 | ) |
| Purchase of natural gas in place | | 8,890,145 |
| | 2,288,166 |
| | — |
|
| Sale of natural gas in place | | (1,210 | ) | | — |
| | (61 | ) |
| Extensions, discoveries and other additions | | 2,164,578 |
| | 2,241,528 |
| | 1,955,935 |
|
| Production | | (794,677 | ) | | (700,967 | ) | | (561,986 | ) |
| End of year | | 19,830,236 |
| | 12,331,867 |
| | 9,110,311 |
|
| Proved developed reserves: | | |
| | |
| | |
|
| Beginning of year | | 6,074,958 |
| | 5,652,989 |
| | 4,257,377 |
|
| End of year | | 10,152,543 |
| | 6,074,958 |
| | 5,652,989 |
|
| Proved undeveloped reserves: | | | | | | |
| Beginning of year | | 6,256,909 |
| | 3,457,322 |
| | 5,518,577 |
|
| End of year | | 9,677,693 |
| | 6,256,909 |
| | 3,457,322 |
|
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| 2020 | | 2019 | | 2018 |
| (Mbbl) |
| NGLs | | | | | |
| Proved developed and undeveloped reserves: | | | | | |
| Balance at January 1 | 126,955 | | | 162,395 | | | 258,507 | |
| Revision of previous estimates | 6,825 | | | (30,312) | | | (33,653) | |
| Purchase of NGLs in place | 25,879 | | | 0 | | | 0 | |
| Sale of NGLs in place | (289) | | | 0 | | | (59,080) | |
| Extensions, discoveries and other additions | 1,757 | | | 6,177 | | | 12,895 | |
| Production | (12,365) | | | (11,305) | | | (16,274) | |
| Balance at December 31 | 148,762 | | | 126,955 | | | 162,395 | |
| Proved developed reserves: | | | | | |
| Balance at January 1 | 100,945 | | | 106,879 | | | 180,170 | |
| Balance at December 31 | 141,489 | | | 100,945 | | | 106,879 | |
| Proved undeveloped reserves: | | | | | |
| Balance at January 1 | 26,010 | | | 55,516 | | | 78,337 | |
| Balance at December 31 | 7,273 | | | 26,010 | | | 55,516 | |
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (Mbbl) |
| Oil | | | | | |
| Proved developed and undeveloped reserves: | | | | | |
| Balance at January 1 | 5,077 | | | 6,159 | | | 10,731 | |
| Revision of previous estimates | 250 | | | (428) | | | 6,217 | |
| Purchase of oil in place | 2,660 | | | 0 | | | 0 | |
| Sale of oil in place | 0 | | | 0 | | | (10,447) | |
| Extensions, discoveries and other additions | 234 | | | 168 | | | 338 | |
| Production | (804) | | | (822) | | | (680) | |
| Balance at December 31 | 7,417 | | | 5,077 | | | 6,159 | |
| Proved developed reserves: | | | | | |
| Balance at January 1 | 4,466 | | | 3,489 | | | 10,731 | |
| Balance at December 31 | 7,016 | | | 4,466 | | | 3,489 | |
| Proved undeveloped reserves: | | | | | |
| Balance at January 1 | 611 | | | 2,670 | | | 0 | |
| Balance at December 31 | 401 | | | 611 | | | 2,670 | |
|
| | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands of Bbls) |
| Oil (a) | | |
| | |
| | |
|
| Proved developed and undeveloped reserves: | | |
| | |
| | |
|
| Beginning of year | | 6,395 |
| | 5,900 |
| | 5,005 |
|
| Revision of previous estimates | | 5,103 |
| | 1,159 |
| | 1,219 |
|
| Purchase of oil in place | | 355 |
| | 3 |
| | — |
|
| Sale of oil in place | | (139 | ) | | — |
| | — |
|
| Extensions, discoveries and other additions | | 9 |
| | 62 |
| | 419 |
|
| Production | | (992 | ) | | (729 | ) | | (743 | ) |
| End of year | | 10,731 |
| | 6,395 |
| | 5,900 |
|
| Proved developed reserves: | | |
| | |
| | |
|
| Beginning of year | | 6,395 |
| | 5,900 |
| | 5,005 |
|
| End of year | | 10,731 |
| | 6,395 |
| | 5,900 |
|
| Proved undeveloped reserves: | | | | | | |
| Beginning of year | | — |
| | — |
| | — |
|
| End of year | | — |
| | — |
| | — |
|
(a)One thousand Bbl equals approximately 6 million cubic feet (MMcf).
|
| | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Bbls) |
| NGLs (a) | | | | | |
| Proved developed and undeveloped reserves: | |
| | | | |
| Beginning of year | 189,695 |
| | 138,481 |
| | 155,494 |
|
| Revision of previous estimates | (6,189 | ) | | 21,322 |
| | (23,743 | ) |
| Purchase of NGLs in place | 82,894 |
| | 17,932 |
| | — |
|
| Sale of NGLs in place | (100 | ) | | — |
| | — |
|
| Extensions, discoveries and other additions | 10,084 |
| | 23,797 |
| | 15,437 |
|
| Production | (17,877 | ) | | (11,837 | ) | | (8,707 | ) |
| End of year | 258,507 |
| | 189,695 |
| | 138,481 |
|
| Proved developed reserves: | |
| | | | |
| Beginning of year | 121,605 |
| | 98,528 |
| | 89,830 |
|
| End of year | 180,170 |
| | 121,605 |
| | 98,528 |
|
| Proved undeveloped reserves: | | | | | |
| Beginning of year | 68,090 |
| | 39,953 |
| | 65,664 |
|
| End of year | 78,337 |
| | 68,090 |
| | 39,953 |
|
(a)One thousand Bbl equals approximately 6 million cubic feet (MMcf).
2017 Changes in Reserves
Transfer•Conversions of 9872,102 Bcfe of proved undeveloped reserves to proved developed reserves.
Increase of 9,390 Bcfe associated with the acquisition of proved developed reserves (3,330 Bcfe) and proved undeveloped reserves (6,060 Bcfe) in the Company’s Marcellus, Upper Devonian and Utica plays.
•Extensions, discoveries and other additions of 2,2253,446 Bcfe, which exceeded the 20172020 production of 9081,498 Bcfe. Extensions, discoveries and other additions included an increase of 2,096 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved using reliable technologies which expanded the number of our technically proven locations, 1,295 Bcfe due to additions associated with directly offsetting development, 31 Bcfe from extension of proved undeveloped reserves lateral lengths and 24 Bcfe from converting unproved reserves to proved developed reserves.
•Negative revisions of 3,522510 Bcfe from proved undeveloped locations primarily due to 3,074 Bcfe from locations that are no longer anticipatedexpected to be drilleddeveloped within 5five years of initial booking as proved reserves as a result of acquiring new acreage. The acquired acreage presents opportunitiesrevisions to drill considerably longer laterals, realize operational efficienciesthe Company’s five-year drilling plan allowing for continued alignment with the Company’s combo-development strategy. This includes 245 Bcfe from lower pricing that impacted well economics, shifting capital from the Ohio Utica, to Pennsylvania and improve overall returns.West Virginia Marcellus, and 265 Bcfe as a result of continued implementation of the Company’s combo-development strategy.
•Negative revisions of 477384 Bcfe primarily from proved developed locations as a result of negative curve revisions in Ohio Utica.
•Positive revisions to proved undeveloped locations of 155 Bcfe due primarily to changes in working interests and net revenue interests as well as type curve updates.
•Purchase of hydrocarbons in place of 1,381 Bcfe due to increased reserves from producing wells.the Chevron Acquisition described in Note 6.
Upward revisions•Sale of 278hydrocarbons in place of 257 Bcfe associated with previously booked locations whose economic lives had been extended due to improved commodity prices.the 2020 Divestitures described in Note 7.
2016 ChangesThe change in Reservesreserves during the year ended December 31, 2019 resulted from the following:
Transfer•Conversions of 6472,646 Bcfe of proved undeveloped reserves to proved developed reserves.
Increase of 2,396 Bcfe associated with the acquisition of proved developed reserves (320 Bcfe) and proved undeveloped reserves (2,076 Bcfe) in the Company’s Marcellus and Upper Devonian plays.
•Extensions, discoveries and other additions of 2,3852,068 Bcfe, which exceeded the 20162019 production of 7761,508 Bcfe. Extensions, discoveries and other additions included an increase of 1,796 Bcfe from proved undeveloped additions associated with acreage that was previously unproved, but became proved due to 2019 reserve development that expanded the number of the Company's technically proven locations, implementation of, and alignment with, the Company's combo-development strategy and revisions to the Company's five-year drilling plan; 156 Bcfe from converting unproved reserves to proved developed reserves; and 116 Bcfe from extension of proved undeveloped reserves lateral lengths.
•Negative revisions of 5094,508 Bcfe from proved undeveloped locations primarily due to 389 Bcfe from economic locations that the Company no longer expects to develop within 5 years of booking, along with the removal of locations that are no longer economicexpected to be developed within five years of initial booking as determinedproved reserves as a result of implementation of the Company's combo-development strategy, which has refocused operations in accordance with Securitiesthe Company's core assets and Exchange Commission (SEC) pricing requirements.driven execution of new development sequencing processes that emphasize productivity. While these efforts are expected to result in decreased well costs, they negatively impact proved undeveloped reserves as a result of (i) derecognizing previously-recorded proved undeveloped reserves that are now outside the Company's substantially revised five-year capital allocation program for purposes of the Company's reserves calculations and (ii) executing new development sequencing processes that will result in increased probable-to-proved developed conversion.
Upward revisions
The change in reserves during the year ended December 31, 2018 resulted from the following:
•Conversions of 68 Bcfe from proved developed locations, primarily due to increased reserves from producing wells.
Negative revisions of 31 Bcfe associated with previously booked locations whose economic lives had been shortened due to reduced commodity prices.
2015 Changes in Reserves
Transfer of 1,5282,722 Bcfe of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 2,0514,739 Bcfe, which exceeded the 20152018 production of 6191,495 Bcfe. Extensions, discoveries and other additions included an increase of 315 Bcfe from proved developed reserves extensions from reservoirs underlying acreage not previously booked as proved in the Company's Ohio, Pennsylvania and West Virginia Marcellus fields; 886 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company's Ohio, Pennsylvania and West Virginia Marcellus fields; and 3,538 Bcfe from other proved undeveloped additions associated with acreage that was excluded from prior year proved reserves bookings, but subsequently became proved due to inclusion within the Company's five-year drilling plan.
•Negative revisions of 2,3211,273 Bcfe from proved undeveloped locations due primarily to the removal of locations that wereare no longer economic as determined in accordance with SEC pricing requirements and from 342 Bcfe from economic locations that the Company no longer expectsexpected to developbe developed within 5five years of booking.initial booking as proved reserves as a result of changes in the Company's future development plans to focus more heavily on developing the Company's core Pennsylvania assets.
•Upward revisions of 386148 Bcfe from proved developed locations, due primarily due to increased reserves from producing wells.wells and improved commodity prices.
Negative revisions•Sale of 259hydrocarbons in place of 1,749 Bcfe associated with previously booked locations whose economic lives had been shortened due to reduced commodity prices.the 2018 Divestitures described in Note 7.
During 2015, the Company revised its approach utilized to determine the gathering cost assumption within the Company's determination of reserves, which management believes to be a significant cost assumption included in the calculation of reserves. The Company believes the methodology that is currently utilized to determine the gathering rate reflects the Company’s current cash operating costs and gives consideration to EQT’s significant ownership interest in EQGP, EQM and RMP. Previously, the Company developed the gathering cost assumption based on the direct operating costs attributable to the operation of the wholly-owned midstream assets. Due to additional dropdowns of midstream assets from EQT to EQM in 2015 and the resulting increase in the proportion of the volumes that are gathered using EQM owned gathering assets, the current gathering rate assumption was developed in consideration of EQT’s significant ownership interest in its consolidated subsidiaries.
Standard Measure of Discounted Future Cash Flow
Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.
The following table summarizes estimated future net cash flows from natural gas and crude oil reserves.
| | | | | | | | | | | | | | | | | |
| December 31, |
| | 2020 | | 2019 | | 2018 |
| | (Thousands) |
| Future cash inflows (a) | $ | 27,976,557 | | | $ | 42,499,686 | | | $ | 60,603,624 | |
| Future production costs (b) | (16,344,965) | | | (19,114,076) | | | (20,463,567) | |
| Future development costs | (2,268,109) | | | (2,617,731) | | | (5,854,503) | |
| Future income tax expenses | (1,820,341) | | | (3,013,667) | | | (6,823,621) | |
| Future net cash flow | 7,543,142 | | | 17,754,212 | | | 27,461,933 | |
| 10% annual discount for estimated timing of cash flows | (4,176,684) | | | (9,261,539) | | | (15,850,035) | |
| Standardized measure of discounted future net cash flows | $ | 3,366,458 | | | $ | 8,492,673 | | | $ | 11,611,898 | |
(a)The majority of the Company's production is sold through liquid trading points on interstate pipelines.
For 2020, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $39.54per Bbl for West Texas Intermediate (WTI) less regional adjustments of $18.60 per Bbl, or $20.94 per Bbl, and $1.985 per MMBtu for NYMEX less regional adjustments of $0.68 per MMBtu, or $1.38 per Mcf. Regional adjustments were calculated using historical average realized prices received by the Company in the Appalachian Basin. For 2020, NGL pricing using average first-day-of-the-month closing prices for the prior twelve months for NGL components, adjusted using the regional component makeup of proved NGLs, resulted in a price of $11.97 per Bbl.
For 2019, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $55.69per Bbl for WTI less regional adjustments of $14.26 per Bbl, or $41.43 per Bbl, and $2.58 per MMBtu for NYMEX less regional adjustments of $0.29 per MMBtu, or $2.41 per Mcf. Regional adjustments were calculated using historical average realized prices received by the Company in the Appalachian Basin. For 2019, NGL pricing using average first-day-of-the-month closing prices for the prior twelve months for NGL components, adjusted using the regional component makeup of proved NGLs, resulted in a price of $16.81 per Bbl.
For 2018, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $65.56 per Bbl for WTI less regional adjustments, $2.888 per Dth for Columbia Gas Transmission Corp., $2.568 per Dth for Dominion Transmission, Inc., $2.587 per Dth for Texas Eastern Transmission Corp., $2.320 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $2.939 per Dth for the Rockies Express Pipeline Zone 3. For 2018, NGL pricing using average first-day-of-the-month closing prices for the prior twelve months for NGL components, adjusted using the regional component makeup of produced NGLs, resulted in prices of $21.93 per Bbl from certain West Virginia Marcellus reserves and $33.89 per Bbl from Ohio Utica reserves.
(b)Includes approximately $1,554 million, $1,186 million and $883 million for future plugging and abandonment costs as of December 31, 2017 includes the impact of the Tax Reform Legislation, which resulted in a lower federal income tax rate than the prior years presented. 2020, 2019 and 2018, respectively.
Estimated future net cash flows from natural gas and oil reserves are as follows at December 31:
|
| | | | | | | | | | | | |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Future cash inflows (a) | | $ | 51,423,920 |
| | $ | 24,011,281 |
| | $ | 17,619,037 |
|
| Future production costs | | (18,379,892 | ) | | (14,864,126 | ) | | (10,963,285 | ) |
| Future development costs | | (5,637,676 | ) | | (3,778,698 | ) | | (2,377,650 | ) |
| Future income tax expenses | | (5,811,125 | ) | | (1,753,067 | ) | | (1,333,989 | ) |
| Future net cash flow | | 21,595,227 |
| | 3,615,390 |
| | 2,944,113 |
|
| 10% annual discount for estimated timing of cash flows | | (12,593,293 | ) | | (2,626,636 | ) | | (1,966,559 | ) |
| Standardized measure of discounted future net cash flows | | $ | 9,001,934 |
| | $ | 988,754 |
| | $ | 977,554 |
|
|
| |
(a) | The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017 of $51.34 per Bbl of oil (first day of each month closing price for West Texas Intermediate (WTI)) less regional adjustments, $2.801 per Dth for Columbia Gas Transmission Corp., $2.100 per Dth for Dominion Transmission, Inc., $2.914 per Dth for the East Tennessee Natural Gas Pipeline, $2.058 per Dth for Texas Eastern Transmission Corp., $1.995 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.321 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.665 per Dth for Waha, and $2.840 per Dth for the Rockies Express Pipeline Zone 3. For 2017, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2017 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $23.07 per Bbl of NGLs from certain West Virginia Marcellus reserves, $31.11 per Bbl of NGLs from certain Kentucky reserves, $29.47 per Bbl for Ohio Utica reserves, and $27.93 per Bbl for Permian reserves. |
| |
| The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016 of $42.75 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.342 per Dth for Columbia Gas Transmission Corp., $1.348 per Dth for Dominion Transmission, Inc., $2.334 per Dth for the East Tennessee Natural Gas Pipeline, $1.325 per Dth for Texas Eastern Transmission Corp., $1.305 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $1.862 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.343 per Dth for Waha, and $2.402 per Dth for the Rockies Express Pipeline Zone 3. For 2016, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2016 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $13.87 per Bbl of NGLs from certain West Virginia Marcellus reserves, $17.27 per Bbl of NGLs from certain Kentucky reserves, $14.71 per Bbl for Ohio Utica reserves, and $18.91 per Bbl for Permian reserves. |
| |
| The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2015, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2015 of $50.28 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.506 per Dth for Columbia Gas Transmission Corp., $1.394 per Dth for Dominion Transmission, Inc., $2.552 per Dth for the East Tennessee Natural Gas Pipeline, $1.428 per Dth for Texas Eastern Transmission Corp., $1.079 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.430 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.473 per Dth for Waha, and $2.549 per Dth for Houston Ship Channel. For 2015, NGLs pricing using arithmetic averages of the closing prices on the first day of each month during 2015 for NGLs components and adjusted using the regional component makeup of produced NGLs resulted in prices of $17.60 per Bbl of NGLs from certain West Virginia Marcellus reserves, $21.69 per Bbl of NGLs from certain Kentucky reserves, $16.84 per Bbl for Ohio Utica reserves, and $17.51 per Bbl for Permian reserves. |
Holding production and development costs constant, a changean increase in price of $0.20$0.10 per Dth for natural gas, $10 per barrel for oilNGLs and $10 per barrel for NGLsoil would result in a change in the December 31, 20172020 discounted future net cash flows before income taxes of the Company’sCompany's proved reserves of approximately $1.8 billion, $50.4$929 million, $241 million and $978.6$630 million, respectively.
Summary ofThe following table summarizes the changes in the standardized measure of discounted future net cash flows for the years ended December 31:flows.
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (Thousands) |
| Net sales and transfers of natural gas and oil produced | $ | (784,163) | | | $ | (1,884,877) | | | $ | (2,802,742) | |
| Net changes in prices, production and development costs | (6,761,447) | | | (3,502,434) | | | 2,949,606 | |
| Extensions, discoveries and improved recovery, net of related costs | 714,808 | | | 870,504 | | | 1,616,653 | |
| Development costs incurred | 797,796 | | | 1,002,389 | | | 1,630,506 | |
| Net purchase of minerals in place | 350,075 | | | 0 | | | 0 | |
| Net sale of minerals in place | (226,497) | | | 0 | | | (849,162) | |
| Revisions of previous quantity estimates | (324,415) | | | (2,080,040) | | | (811,576) | |
| Accretion of discount | 849,267 | | | 900,004 | | | 834,026 | |
| Net change in income taxes | 152,978 | | | 1,444,368 | | | (289,549) | |
| Timing and other | 105,383 | | | 130,861 | | | 332,202 | |
| Net (decrease) increase | (5,126,215) | | | (3,119,225) | | | 2,609,964 | |
| Balance at January 1 | 8,492,673 | | | 11,611,898 | | | 9,001,934 | |
| Balance at December 31 | $ | 3,366,458 | | | $ | 8,492,673 | | | $ | 11,611,898 | |
|
| | | | | | | | | | | | |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands) |
| Sales and transfers of natural gas and oil produced – net | | $ | (1,313,249 | ) | | $ | (539,980 | ) | | $ | (813,166 | ) |
| Net changes in prices, production and development costs | | 2,236,183 |
| | (1,129,026 | ) | | (5,546,405 | ) |
| Extensions, discoveries and improved recovery, less related costs | | 1,269,712 |
| | 590,885 |
| | 264,735 |
|
| Development costs incurred | | 712,635 |
| | 402,891 |
| | 971,186 |
|
| Purchase of minerals in place – net | | 5,357,921 |
| | 592,078 |
| | — |
|
| Sale of minerals in place – net | | (284 | ) | | — |
| | (43 | ) |
| Revisions of previous quantity estimates | | (297,437 | ) | | (60,959 | ) | | (1,541,418 | ) |
| Accretion of discount | | 115,437 |
| | 122,674 |
| | 600,099 |
|
| Net change in income taxes | | (1,477,603 | ) | | (91,823 | ) | | 2,424,200 |
|
| Timing and other (a) | | 1,409,865 |
| | 124,460 |
| | (191,662 | ) |
| Net increase (decrease) | | 8,013,180 |
| | 11,200 |
| | (3,832,474 | ) |
| Beginning of year | | 988,754 |
| | 977,554 |
| | 4,810,028 |
|
| End of year | | $ | 9,001,934 |
| | $ | 988,754 |
| | $ | 977,554 |
|
| |
(a) | Increase in 2017 primarily driven by timing changes to the Company’s development plan as a result of the Rice Merger. |
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.applicable.
Item 9A.Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of management, including the Company’sCompany's Principal Executive Officer and Principal Financial Officer, an evaluation of the Company’sCompany's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company’sCompany's disclosure controls and procedures were effective as of the end of the period covered by this report.
Management’sManagement's Report on Internal Control over Financial Reporting
The Company's management of EQT is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act). EQT’sThe Company's internal control system is designed to provide reasonable assurance to the Company’sCompany's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.
EQT’sThe Company's management assessed the effectiveness of the Company’sCompany's internal control over financial reporting as of December 31, 2017.2020. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2017.2020. Management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entitiesassets acquired in the Rice MergerChevron Acquisition on November 13, 2017. Rice’s total30, 2020. Total assets acquired and total operating revenues represented approximately 45%5% of the Company’s consolidated total assets at December 31, 20172020 and 10%less than 1% of the Company’s consolidated total operating revenues for the year ended December 31, 2017.2020.
Ernst & Young LLP (Ernst & Young), the independent registered public accounting firm that audited the Company’sCompany's Consolidated Financial Statements, has issued an attestation report on the Company’sCompany's internal control over financial
reporting.
Ernst & Young’sYoung's attestation report on the Company’sCompany's internal control over financial reporting appears in Part II, Item 88., of this Annual Report on Form 10-K and is incorporated herein by reference herein.reference.
Changes in Internal Control over Financial Reporting
As noted under “Management’s Report on Internal Control over Financial Reporting,” management’s assessment of, and conclusion on, the effectiveness ofThere were no changes in internal control over financial reporting did not include(as such term is defined in Rule 13a-15(f) under the internal controls of the entities acquired in the Rice Merger on November 13, 2017. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating Rice’s and the Company’s internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there were no changes in the Company’s internal control over financial reportingExchange Act) that occurred during the fourth quarter of 20172020 that have materially affected, or are reasonably likely to materially affect, the Company’sCompany's internal control over financial reporting.
The Company is in the process of integrating the assets acquired in the Chevron Acquisition into the Company's internal controls over financial reporting.
Item 9B.Other Information
We intend to hold our 2018 annual meeting more than 30 days after the anniversary of our 2017 annual meeting. Accordingly, we have extended the deadline for receipt of shareholder proposals pursuant to Rule 14a-8 of the Exchange Act to February 28, 2018. The date of our annual meeting and the deadline for submitting director nominations and other proposals pursuant to our bylaws will be announced at a later time.Not Applicable.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The following information is incorporated herein by reference from the Company’sCompany's definitive proxy statement relating to the 20182021 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of the Company’sCompany's fiscal year ended December 31, 2017:2020:
•Information required by Item 401 of Regulation S-K with respect to directors is incorporated herein by reference from the sections captioned “Item No. 1 – Election of Directors,”"Director Nominees" and “Corporate"Director Independence" under "Corporate Governance and Board Matters”Matters" in the Company’sCompany's definitive proxy statement;
Information required by Item 405 of Regulation S-K with respect to compliance with Section 16(a) of the Exchange Act is incorporated herein by reference from the section captioned “Equity Ownership – Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement;
•Information required by Item 407(d)(4) of Regulation S-K with respect to disclosure of the existence of the Company’sCompany's separately-designated standing Audit Committee and the identification of the members of the Audit Committee is incorporated herein by reference from the section captioned “Corporate"Corporate Governance and Board Matters – Board Meetings and Committees – Audit Committee”Committee" in the Company’sCompany's definitive proxy statement; and
•Information required by Item 407(d)(5) of Regulation S-K with respect to disclosure of the Company’sCompany's audit committee financial expert is incorporated herein by reference from the section captioned “Corporate"Corporate Governance and Board Matters – Board Meetings and Committees – Audit Committee”Committee" in the Company’sCompany's definitive proxy statement.
Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Annual Report on Form 10-K under the caption “Executive"Information about our Executive Officers of the Registrant (as of February 15, 2018)17, 2021),”" and is incorporated herein by reference.
The Company has adopted a code of business conduct and ethics applicable to all directors and employees, including the principal executive officer, principal financial officer and principal accounting officer. The code of business conduct and ethics is posted on the Company’sCompany's website http://www.eqt.com (accessible by clicking on the “Investors”"About" link on the main page, followed by the “Corporate Governance” link"Governance" heading, then the "Charters and the “Charters and Documents”Governance Documents" link), and a printed copy will be delivered free of charge on request by writing to the corporate secretary at EQT Corporation, c/o Corporate Secretary, 625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222. The Company intends to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of business conduct and ethics by posting such information on the Company’sCompany's website.
On November 13, 2017, the Company’s articles of incorporation were amended and restated (as amended and restated, the Restated Articles of Incorporation) to increase the maximum number of directors permitted to be on the Board from twelve to fifteen. This amendment was approved by the Company’s shareholders at a special meeting held on November 9, 2017.
Also on November 13, 2017, the Company’s bylaws were amended and restated (as amended and restated, the Amended and Restated Bylaws) to conform to the Restated Articles of Incorporation by increasing the maximum number of directors permitted to be on the Board from twelve to fifteen.
Item 11. Executive Compensation
The following information is incorporated herein by reference from the Company’sCompany's definitive proxy statement relating to the 20182021 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of the Company’sCompany's fiscal year ended December 31, 2017:2020:
•Information required by Item 402 of Regulation S-K with respect to named executive officer and director compensation is incorporated herein by reference from the sections captioned “Executive Compensation - Compensation"Compensation Discussion and
Analysis,” “Executive Compensation - Compensation" "Compensation Tables,” “Executive Compensation - Compensation" "Compensation Policies and Practices and Risk Management,”" "Pay Ratio Disclosure" and “Directors’ Compensation”"Corporate Governance and Board Matters – Directors' Compensation" in the Company’sCompany's definitive proxy statement; and
•Information required by paragraphs (e)(4) andparagraph (e)(5) of Item 407 of Regulation S-K with respect to certain matters related to the Management Development and Compensation Committee of the Company's Board of Directors is incorporated herein by reference from the sectionssection captioned “Corporate Governance and Board Matters - Compensation"Compensation Committee Interlocks and Insider Participation” and “Executive Compensation - Report of the Management Development and Compensation Committee”Report" in the Company’sCompany's definitive proxy statement.
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by Item 403 of Regulation S-K with respect to stock ownership of significant shareholders, directors and executive officers is incorporated herein by reference to the sections captioned “Equity"Equity Ownership - Stock– Security Ownership of Significant Shareholders”Certain Beneficial Owners" and “Equity"Equity Ownership - Equity– Security Ownership of Directors and Executive Officers”Management" in the Company’sCompany's definitive proxy statement relating to the 20182021 annual meeting of shareholders, which will be filed with the SEC within 120 days after the close of the Company’sCompany's fiscal year ended December 31, 2017.2020.
Equity Compensation Plan Information
The following table and related footnotes provide information as of December 31, 20172020 with respect to shares of the Company’sCompany's common stock that may be issued under the Company’sCompany's existing equity compensation plans, including the 2020 Long-Term Incentive Plan (2020 LTIP), 2019 Long-Term Incentive Plan (2019 LTIP), 2014 Long-Term Incentive Plan (2014 LTIP), the 2009 Long-Term Incentive Plan (2009 LTIP), the 1999 Non-Employee Directors’ Stock Incentive Plan (1999 NEDSIP), the 2005 Directors’ Deferred Compensation Plan (2005 DDCP), the 1999 Directors’ Deferred Compensation Plan (1999 DDCP), the 2008 Employee Stock Purchase Plan (2008 ESPP), and the 2014 Rice Energy Inc. 2014 Long-Term Incentive2005 Directors' Deferred Compensation Plan (Rice LTIP)(2005 DDCP):
| | | Plan Category | | Number Of Securities To Be Issued Upon Exercise Of Outstanding Options, Warrants and Rights (A) | | Weighted Average Exercise Price of Outstanding Options, Warrants and Rights (B) | | Number Of Securities Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected In Column A) (C) | | Plan Category | | Number Of Securities
To Be Issued Upon
Exercise Of Outstanding
Options, Warrants
and Rights
(A) | | Weighted Average
Exercise Price Of
Outstanding Options,
Warrants and Rights
(B) | | Number Of Securities
Remaining Available For
Future Issuance Under Equity
Compensation Plans, Excluding
Securities Reflected In Column A
(C) | |
Equity Compensation Plans Approved by Shareholders (1) | | 3,835,415 |
| (2) | $ | 63.42 |
| (3) | 3,068,980 |
| (4) | Equity Compensation Plans Approved by Shareholders (1) | | 10,333,813 | | (2) | $ | 19.79 | | (3) | 12,337,169 | | (4) |
Equity Compensation Plans Not Approved by Shareholders (5) | | 89,891 |
| (6) | N/A |
| | 4,872,501 |
| | Equity Compensation Plans Not Approved by Shareholders (5) | | 45,709 | | (6) | N/A | | 127,135 | | (7) |
| Total | | 3,925,306 |
| | $ | 63.42 |
| | 7,941,481 |
| | Total | | 10,379,522 | | | $ | 19.79 | | | 12,464,304 | | |
| |
(1)
| Consists of the 2014 LTIP, the 2009 LTIP, the 1999 NEDSIP and the 2008 ESPP. Effective as of April 30, 2014, in connection with the adoption of the 2014 LTIP, the Company ceased making new grants under the 2009 LTIP. Effective as of April 22, 2009, in connection with the adoption of the 2009 LTIP, the Company ceased making new grants under the 1999 NEDSIP. The 2009 LTIP and the 1999 NEDSIP remain effective solely for the purpose of issuing shares upon the exercise or payout of awards outstanding under such plans on April 30, 2014 (for the 2009 LTIP) and April 22, 2009 (for the 1999 NEDSIP). |
| |
(2)
| Consists of (i) 520,100 shares subject to outstanding stock options under the 2014 LTIP; (ii) 2,569,766 shares subject to outstanding performance awards under the 2014 LTIP, inclusive of dividend reinvestments thereon (counted at a 3X multiple assuming maximum performance is achieved under the awards (representing 856,589 target awards and dividend reinvestments thereon)); (iii) 76,532 shares subject to outstanding directors' deferred stock units under the 2014 LTIP, inclusive of dividend reinvestments thereon; (iv) 628,800 shares subject to outstanding stock options under the 2009 LTIP; (v) 34,983 shares subject to outstanding directors’ deferred stock units under the 2009 LTIP, inclusive of dividend reinvestments thereon; and (vi) 5,234 shares subject to outstanding directors’ deferred stock units under the 1999 NEDSIP, inclusive of dividend reinvestments thereon.
|
| |
(3)
| The weighted-average exercise price is calculated based solely upon outstanding stock options under the 2014 LTIP and the 2009 LTIP and excludes deferred stock units under the 2014 LTIP, the 2009 LTIP and the 1999 NEDSIP and performance awards under the 2014 LTIP and the 2009 LTIP. The weighted average remaining term of the stock options was 6.25 years as of December 31, 2017. |
| |
(4)
| Consists of (i) 2,511,109 shares available for future issuance under the 2014 LTIP, (ii) 4,899 shares under the 2009 LTIP and (iii) 552,972 shares available for future issuance under the 2008 ESPP. As of December 31, 2017, 5,004 shares were subject to purchase under the 2008 ESPP. |
| |
(5)
| Consists of the 2005 DDCP, the 1999 DDCP and the Rice LTIP each of which is described below. |
| |
(6)
| Consists of (i) 25,529 shares invested in the EQT Common Stock Fund, payable in shares of common stock, allocated to non-employee directors’ accounts under the 2005 DDCP and the 1999 DDCP as of December 31, 2017; and (ii) 64,362 performance awards under the Rice LTIP, inclusive of dividend reinvestments thereon (based upon amounts previously confirmed in connection with the Rice Merger). |
(1)Consists of the 2020 LTIP, 2019 LTIP, 2014 LTIP, the 2009 LTIP, and the 2008 ESPP. Effective as of May 1, 2020, with the adoption of the 2020 LTIP, the Company ceased making new grants under the 2019 LTIP. Effective as of July 10, 2019 in connection with the adoption of the 2019 LTIP, the Company ceased making new grants under the 2014 LTIP. Effective as of April 30, 2014, in connection with the adoption of the 2014 LTIP, the Company ceased making new grants under the 2009 LTIP. The 2019 LTIP, 2014 LTIP, and the 2009 LTIP remain effective solely for the purpose of issuing shares upon the exercise or payout of awards outstanding under such plans on May 1, 2020 (for the 2019 LTIP), July 10, 2019 (for the 2014 LTIP) and April 30, 2014 (for the 2009 LTIP).
(2)Consists of (i) 2,053,512 shares subject to outstanding performance awards under the 2019 LTIP, inclusive of dividend reinvestments thereon (counted at a 3X multiple assuming maximum performance is achieved under the awards (representing 1,369,008 target awards and dividend reinvestments thereon)), (ii) 2,240,000 shares subject to outstanding stock options and stock appreciation rights under the 2019 LTIP, (iii) 33,886 shares subject to outstanding directors' deferred stock units under the 2019 LTIP, inclusive of dividend reinvestments thereon, (iv) 3,311,745 shares subject to outstanding performance awards under the 2014 LTIP, inclusive of dividend reinvestments thereon (counted at a 3X multiple assuming maximum performance is achieved under the awards (representing 2,304,439 target and confirmed awards and dividend reinvestments thereon)), (v) 1,598,415 shares subject to outstanding stock options under the 2014 LTIP, (vi) 117,680 shares subject to outstanding directors' deferred stock units under the 2014 LTIP, inclusive of dividend reinvestments thereon, (vii) 956,314 shares subject to outstanding stock options under the 2009 LTIP; and (viii) 22,261 shares subject to outstanding directors' deferred stock units under the 2009 LTIP, inclusive of dividend reinvestments thereon.
(3)The weighted-average exercise price is calculated solely based on outstanding stock options and stock appreciation rights under the 2019 LTIP, 2014 LTIP and the 2009 LTIP and excludes deferred stock units under the 2019 LTIP, 2014 LTIP, and the 2009 LTIP
and performance awards under the 2019 LTIP, 2014 LTIP and 2009 LTIP. The weighted average remaining term of the outstanding stock options and stock appreciation rights was 5.3 years and 9.0 years, respectively, as of December 31, 2020.
(4)Consists of (i) 12,044,453 shares available for future issuance under the 2020 LTIP and (ii) 292,716 shares available for future issuance under the 2008 ESPP. As of December 31, 2020, no shares were subject to purchase under the 2008 ESPP.
(5)Consists of the 2005 DDCP which is described below.
(6)Consists entirely of shares invested in the EQT common stock fund, payable in shares of common stock, allocated to non-employee directors' accounts under the 2005 DDCP as of December 31, 2020.
(7)Consists entirely of shares available for future issuance under the 2005 DDCP as of December 31, 2020.
2005 Directors’Directors' Deferred Compensation Plan
The 2005 DDCP was adopted by the Management Development and Compensation Committee, effective January 1, 2005. Neither the original adoption of the plan nor its amendments required approval by the Company’sCompany's shareholders. The plan allows non-employee directors to defer all or a portion of their directors’directors' fees and retainers. Amounts deferred are payable on or following retirement from the Company's Board of Directors unless an early payment is authorized after the director suffers an unforeseeable financial emergency. In addition to deferred directors’directors' fees and retainers, the deferred stock units granted to directors on or after January 1, 2005 under the 1999 NEDSIP, the 2009 LTIP and the 2014 LTIP are administered under this plan.
1999 Directors’ Deferred Compensation Plan
The 1999 DDCP was suspended as of December 31, 2004. The plan continues to operate for the sole purpose of administering vested amounts deferred under the plan on or prior to December 31, 2004. Deferred amounts are generally payable on or following retirement from the Board, but may be payable earlier if an early payment is authorized after a director suffers an unforeseeable financial emergency. In addition to deferred directors’ fees and retainers and a one-time grant of deferred shares in 1999 resulting from the curtailment of the directors’ retirement plan, the deferred stock units granted to directors and vested prior to January 1, 2005 under the 1999 NEDSIP are administered under this plan.
Rice Energy Inc. 2014 Long-Term Incentive Plan
The board of directors of Rice Energy adopted the Rice Energy Inc. 2014 Long-Term Incentive Plan (as amended and restated effective as of May 9, 2014), which was assumed by the Company in connection with the Rice Merger for employees and non-employee directors of the Company and any of its affiliates. The Company may issue long-term equity based awards under the plan. Employees and non-employee directors of the Company or any affiliate, including subsidiaries, are eligible to receive awards under the plan.
The aggregate number of shares that may be issued under the plan is 6,475,000 shares, subject to proportionate adjustment in the event of stock splits, recapitalizations, mergers and similar events. Shares subject to awards that (i) expire or are canceled, forfeited, exchanged, settled in cash, or otherwise terminated; and (ii) are delivered by the participant or withheld from an award to satisfy tax withholding requirements, and delivered or withheld to pay the exercise price of an option, will again be available for awards under the plan.
The plan is administered by the Committee, except to the extent the Board elects to administer the plan.
The plan authorizes the granting of awards in any of the following forms: performance awards, restricted stock units, dividend equivalent rights, market-priced options to purchase stock, stock appreciation rights, other stock-based awards that are denominated or payable in, valued in whole or in part by reference to, or otherwise based on stock, and cash-based awards.
The Board may amend, alter, suspend, discontinue or terminate the plan at any time, except that no amendment may be made without the approval of the Company’s shareholders if shareholder approval is required by any federal or state law or regulation or by the rules of any exchange on which the stock may then be listed, or if the amendment, alteration or other change increases the number of shares available under the plan, or if the Board in its discretion determines that obtaining such shareholder approval is for any reason advisable.
Shares to be delivered pursuant to awards under the plan may be shares made available from (i) authorized but unissued shares of stock, (ii) treasury stock, or (iii) previously issued shares of stock reacquired by the Company, including shares purchased on the open market.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by Items 404 and 407(a) of Regulation S-K with respect to director independence and related person transactions and director independence is incorporated herein by reference to the sectionsections captioned “Corporate"Related Person Transactions," "Director Nominees" and "Director Independence" under "Corporate Governance and Board Matters – Independence and Related Person Transactions”Matters" in the Company’sCompany's definitive proxy statement relating to the 20182021 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of the Company’sCompany's fiscal year ended December 31, 2017.2020.
Item 14. Principal Accounting Fees and Services
Information required by Item 9(e) of Schedule 14A is incorporated herein by reference to the section captioned “Item No. 3 – Ratification of Appointment of Independent Registered Public Accounting Firm”"Audit Matters" in the Company’sCompany's definitive proxy statement relating to the 20182021 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of the Company’sCompany's fiscal year ended December 31, 2017.2020.
PART IV
Item 15.Exhibits and Financial StatementStatements Schedules
|
| | | | | | | | | | |
| (a) | 1 | Documents filed as part of this reportFinancial Statements | Page
Reference |
| | | | | |
| | 1. | | All Financial Statements | |
| | | | | |
| | | | Index to Consolidated Financial Statements | Page Reference |
| | | | Statements of Consolidated Operations for each of the three years in the period ended December 31, 20172020 | |
| | | | Statements of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 20172020 | |
| | Consolidated Balance Sheets as of December 31, 2020 and 2019 | |
| | Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 20172020 | |
| | | | Consolidated Balance Sheets as of December 31, 2017 and 2016 | |
| | | | Statements of Consolidated Equity for each of the three years in the period ended December 31, 20172020 | |
| | | | Notes to Consolidated Financial Statements | |
| | | | | |
| 2 | 2.Financial Statements Schedule | | Financial Statement Schedule | |
| | | | | |
| | | | Schedule II - Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, 20172020 | |
| | | | | |
EQT CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 20172020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | | | | |
| Description | | Balance at Beginning of Period | | (Deductions) Additions Charged to
Costs and Expenses | | Additions Charged to Other Accounts | | Deductions | | Balance at End
of Period |
| | (Thousands) |
| Valuation allowance for deferred tax assets: | | | | | | | |
| 2020 | | $ | 423,444 | | | $ | 132,386 | | | $ | 0 | | | $ | (25,838) | | | $ | 529,992 | |
| 2019 | | 351,408 | | | 84,260 | | | 1,114 | | | (13,338) | | | 423,444 | |
| 2018 | | 262,392 | | | 98,311 | | | 0 | | | (9,295) | | | 351,408 | |
|
| | | | | | | | | | | | | | | | | | | | |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | | | | | |
| Description | | Balance at Beginning of Period | | (Deductions) Additions Charged to Costs and Expenses | | Additions Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | | (Thousands) |
| Valuation allowance for deferred tax assets: | | | | | | | |
| | | | | | | | | | | |
| 2017 | | $ | 201,422 |
| | $ | 70,063 |
| | $ | — |
| | $ | (9,093 | ) | | $ | 262,392 |
|
| | | | | | | | | | | |
| 2016 | | $ | 156,084 |
| | $ | 24,706 |
| | $ | 21,536 |
| | $ | (904 | ) | | $ | 201,422 |
|
| | | | | | | | | | | |
| 2015 | | $ | 64,987 |
| | $ | 91,097 |
| | $ | — |
| | $ | — |
| | $ | 156,084 |
|
All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
|
| | | | | | | | | | |
| 3 | Exhibits | | | |
| | | | All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
| |
|
| | | | | | | |
| Exhibits | Description | | | | |
| | 3. | | Exhibits | |
| | | | | |
|
| | | | |
Exhibits | | Description | | Method of Filing |
| | | | |
| Shareholder and Registration Rights Agreement, dated November 12, 2018, between EQT Corporation and Equitrans Midstream Corporation. | Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-3551) filed on November 13, 2018. |
| Tax Matters Agreement, dated November 12, 2018, between EQT Corporation and Plan of Merger dated as of June 19, 2017 among the Company, Eagle Merger Sub I, Inc. and Rice Energy Inc. | Equitrans Midstream Corporation. | Incorporated herein by reference to Exhibit 2.12.3 to Form 8-K (#001-3551) filed on June 19, 2017 |
| | | | November 13, 2018. |
| | Amendment No. 1 to Agreement and Plan of Merger dated as of October 26, 2017 among the Company, Eagle Merger Sub I, Inc. and Rice Energy Inc. | | Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on October 26, 2017 |
| | | | |
| | Purchase and Sale Agreement dated as of September 26, 2016 among Vantage Energy Investment LLC, Vantage Energy Investment II LLC, Rice Energy Inc., Vantage Energy, LLC, and Vantage Energy II, LLC | | Incorporated herein by reference to Exhibit 10.1 to Rice Energy Inc.'s Form 8-K (#001-36273) filed on September 30, 2016 |
| | | | |
| | Restated Articles of Incorporation of EQT Corporation (amended(as amended through November 13, 2017). | | Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on November 14, 2017 |
| | | | 2017. |
| Articles of Amendment to the Restated Articles of Incorporation of EQT Corporation (effective May 1, 2020). | Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on May 4, 2020. |
| | | | | | | | |
| Articles of Amendment to the Restated Articles of Incorporation of EQT Corporation (effective July 23, 2020). | Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on July 23, 2020. |
| | Amended and Restated Bylaws of EQT Corporation (amended(as amended through November 13, 2017) | May 1, 2020). | Incorporated herein by reference to Exhibit 3.33.4 to Form 8-K (#001-3551) filed on November 14, 2017 |
| | | | May 4, 2020. |
| Description of Capital Stock. | Incorporated herein by reference to Exhibit 99.1 to Form 8-K (#001-3551) filed on July 15, 2019. |
| Indenture, dated as of April 1, 1983, between the CompanyEQT Corporation (as successor to Equitable Gas Company) and Pittsburgh National Bank, as Trusteetrustee. | | Incorporated herein by reference to Exhibit 4.01(a) to Form 10-K (#001-3551) for the year ended December 31, 2007 |
| | | | 2007. |
| | Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National BankBank. | | Incorporated herein by reference to Exhibit 4.01(b) to Form 10-K (#001-3551) for the year ended December 31, 1998 |
| | | | 1998. |
| Supplemental Indenture, dated March 15, 1991, between EQT Corporation (as successor to Equitable Resources, Inc.) and Bankers Trust Company. | ResolutionIncorporated herein by reference to Exhibit 4.01(f) to Form 10-K (#001-3551) for the year ended December 31, 1996. |
| Resolutions adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the CompanyEquitable Resources, Inc. and Addenda Nos. 1 through 27, establishing the terms and provisions of the Series A Medium-Term NotesNotes. | | Incorporated herein by reference to Exhibit 4.01(g) to Form 10-K (#001-3551) for the year ended December 31, 1996 |
| | | | 1996. |
| | Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance Committee of the Board of Directors of the CompanyEquitable Resources, Inc. and Addenda Nos. 1 through 8, establishing the terms and provisions of the Series B Medium-Term NotesNotes. | | Incorporated herein by reference to Exhibit 4.01(h) to Form 10-K (#001-3551) for the year ended December 31, 1997 |
| | | | 1997. |
| | Resolution adopted July 14, 1994 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 and 2, establishing the terms and provisions of the Series C Medium-Term Notes | | Incorporated herein by reference to Exhibit 4.01(i) to Form 10-K (#001-3551) for the year ended December 31, 1995 |
| | | | |
| | Second Supplemental Indenture, dated as of June 30, 2008, between the CompanyEQT Corporation, Equitable Resources, Inc., and Deutsche Bank Trust Company Americas, as Trustee,trustee, pursuant to which EQT Corporation assumed the obligations of Equitable Resources, Inc. under the related IndentureIndenture. | | Incorporated herein by reference to Exhibit 4.01(g) to Form 8-K (#001-3551) filed on July 1, 2008 |
| | | | 2008. |
| | Indenture, dated as of July 1, 1996, between the CompanyEQT Corporation (as successor to Equitable Resources, Inc.) and The Bank of New York as(as successor to Bank of Montreal Trust Company,Company), as Trusteetrustee. | | Incorporated herein by reference to Exhibit 4.01(a) to Form S-4 Registration Statement (#333-103178) filed on February 13, 2003 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
|
| | | | |
Exhibits | | Description | | Method of Filing |
| | | | 2003. |
| | Resolutions adopted January 18 and July 18, 1996 by the Board of Directors of the CompanyEquitable Resources, Inc. and Resolution adopted July 18, 1996 by the Executive Committee of the Board of Directors of the Company,Equitable Resources, Inc., establishing the terms and provisions of the 7.75% Debentures issued July 29, 19961996. | | Incorporated herein by reference to Exhibit 4.01(j) to Form 10-K (#001-3551) for the year ended December 31, 1996 |
| | | | 1996. |
| | First Supplemental Indenture, dated as of June 30, 2008, between the CompanyEQT Corporation, Equitable Resources, Inc., and The Bank of New York, as Trustee,trustee, pursuant to which EQT Corporation assumed the obligations of Equitable Resources, Inc. under the related IndentureIndenture. | | Incorporated herein by reference to Exhibit 4.02(f) to Form 8-K (#001-3551) filed on July 1, 2008 |
| | | | 2008. |
| | Indenture, dated as of March 18, 2008, between the CompanyEQT Corporation (as successor to Equitable Resources, Inc.) and The Bank of New York, as Trusteetrustee. | | Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-3551) filed on March 18, 2008 |
| | | | 2008. |
| Cross-reference table for Indenture dated March 18, 2008 (listed as Exhibit 4.04(a) above) and the Trust Indenture Act of 1939, as amended. | ThirdIncorporated herein by reference to Exhibit 4.03(b) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Second Supplemental Indenture, dated as of May 15, 2009June 30, 2008, between the CompanyEQT Corporation, Equitable Resources, Inc. and The Bank of New York, as Trustee,trustee, pursuant to which EQT Corporation assumed the 8.13% Senior Notes due 2019 were issuedobligations of Equitable Resources, Inc. under the related Indenture. | | Incorporated herein by reference to Exhibit 4.14.03(c) to Form 8-K (#001-3551) filed on May 15, 2009 |
| | | | July 1, 2008. |
| | Fourth Supplemental Indenture, dated as of November 7, 2011, between the CompanyEQT Corporation and The Bank of New York Mellon, as Trustee,trustee, pursuant to which the 4.88%4.875% Senior Notes due 2021 were issuedissued. | | Incorporated herein by reference to Exhibit 4.2 to Form 8-K (#001-3551) filed on November 7, 2011 |
| | | | 2011. |
| | Fifth Supplemental Indenture, dated as of October 4, 2017, between the CompanyEQT Corporation and The Bank of New York Mellon, as Trustee,trustee, pursuant to which the Floating Rate Notes due 2020 were issuedissued. | | Incorporated herein by reference to Exhibit 4.3 to Form 8-K (#001-3551) filed on October 4, 20172017. |
| | | | | | | | |
| | Sixth Supplemental Indenture, dated as of October 4, 2017, between the CompanyEQT Corporation and The Bank of New York Mellon, as Trustee,trustee, pursuant to which the 2.50%2.500% Senior Notes due 2020 were issuedissued. | | Incorporated herein by reference to Exhibit 4.5 to Form 8-K (#001-3551) filed on October 4, 2017 |
| | | | 2017. |
| | Seventh Supplemental Indenture, dated as of October 4, 2017, between the CompanyEQT Corporation and The Bank of New York Mellon, as Trustee,trustee, pursuant to which the 3.00%3.000% Senior Notes due 2022 were issuedissued. | | Incorporated herein by reference to Exhibit 4.7 to Form 8-K (#001-3551) filed on October 4, 2017 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
|
| | | | |
Exhibits | | Description | | Method of Filing |
| | | | 2017. |
| | Eighth Supplemental Indenture, dated as of October 4, 2017, between the CompanyEQT Corporation and The Bank of New York Mellon, as Trustee,trustee, pursuant to which the 3.90%3.900% Senior Notes due 2027 were issuedissued. | | Incorporated herein by reference to Exhibit 4.9 to Form 8-K (#001-3551) filed on October 4, 2017 |
| | | | 2017. |
| | Ninth Supplemental Indenture, dated as of August 1, 2014 amongJanuary 21, 2020, between EQT Midstream Partners, LP, the subsidiaries of EQT Midstream Partners, LP party thereto,Corporation and The Bank of New York Mellon, Trust Company, N.A., as Trusteetrustee, pursuant to which the 6.125% Senior Notes due 2025 were issued. | Incorporated herein by reference to Exhibit 4.3 to Form 8-K (#001-3551) filed on January 21, 2020. |
| Tenth Supplemental Indenture, dated January 21, 2020, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the 7.000% Senior Notes due 2030 were issued. | Incorporated herein by reference to Exhibit 4.5 to Form 8-K (#001-3551) filed on January 21, 2020. |
| Eleventh Supplemental Indenture, dated November 16, 2020, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the 5.00% Senior Notes due 2029 were issued. | Incorporated herein by reference to Exhibit 4.014.3 to Form 8-K (#001-3551) filed on November 16, 2020. |
| Indenture, dated April 28, 2020, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the 1.75% Convertible Senior Notes due 2026 were issued. | Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-3551) filed on April 29, 2020. |
| Second Amended and Restated Credit Agreement, dated of July 31, 2017, among EQT Corporation, PNC Bank, National Association, as administrative agent, swing line lender and an L/C issuer and the other lenders party thereto. | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on August 3, 2017. |
| Term Loan Agreement, dated May 31, 2019, among EQT Corporation, PNC Bank, National Association, as administrative agent, and the other lenders party thereto. | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on May 31, 2019. |
| Gas Gathering and Compression Agreement, dated February 26, 2020, among EQT Corporation, EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and EQM Gathering OpCo, LLC. | Incorporated herein by reference to Exhibit 10.01 to Form 10-Q (#001-3551) for the quarter ended March 31, 2020. |
| First Amendment to Gas Gathering and Compression Agreement, dated August 26, 2020, among EQT Corporation, EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and EQM Gathering OpCo, LLC. | Incorporated herein by reference to Exhibit 10.01 to Form 10-Q (#001-3551) for the quarter ended September 30, 2014 |
| | | | 2020. |
| | First Supplemental IndentureLetter Agreement, dated as of AugustNovember 1, 20142020, among EQT Midstream Partners, LP,Corporation, EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and EQM Gathering OpCo, LLC. | Filed herewith as Exhibit 10.03(c). |
| Purchase Agreement, dated April 23, 2020, among EQT Corporation and J.P. Morgan Securities LLC, Barclays Capital Inc. and Credit Suisse Securities (USA) LLC, as representative of the subsidiariesseveral initial purchasers of EQT Midstream Partners, LP party thereto, and The Bank of New York Mellon Trust Company, N.A., as Trustee, pursuant to which the EQT Midstream Partners, LP 4.00%1.75% Convertible Senior Notes due 2024 were issued | 2026 named in Schedule 1 attached thereto. | Incorporated herein by reference to Exhibit 4.0210.1 to Form 10-Q8-K (#001-3551) for the quarter ended September 30, 2014 |
| | | | filed on April 29, 2020. |
| | Second Supplemental Indenture dated asForm of November 4, 2016 between EQT Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A., as Trustee, pursuant to which the EQT Midstream Partners, LP 4.125% Senior Notes due 2026 were issued | Capped Call Confirmation. | Incorporated herein by reference to Exhibit 4.210.2 to EQT Midstream Partners, LP's Form 8-K (#001-35574)(#001-3551) filed on November 4, 2016 |
| | | | April 29, 2020. |
| | EQT Corporation 2009 Long-Term Incentive Plan (as amended and restated through July 11, 2012). | | Incorporated herein by reference to Exhibit 10.2 to Form 10-Q (#001-3551) for the quarter ended June 30, 2012 |
| | | | 2012. |
| | Form of Participant Award Agreement (Stock Option) under 2009 Long-Term Incentive Plan (pre-2012 grants). | | Incorporated herein by reference to Exhibit 10.01(q) to Form 10-K (#001-3551) for the year ended December 31, 2010 |
| | | | 2010. |
| | Form of Amendment to Stock Option Award AgreementsAgreements. | | Incorporated herein by reference to Exhibit 10.3 to Form 10-Q (#001-3551) for the quarter ended June 30, 2011 |
| | | | 2011. |
| | Form of Participant Award Agreement (Stock Option) under 2009 Long-Term Incentive Plan (2012 grants). | | Incorporated herein by reference to Exhibit 10.02(n) to Form 10-K (#001-3551) for the year ended December 31, 20112011. |
| | | | | | | | |
| | Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2009 Long-Term Incentive Plan (pre-2013 grants). | | Incorporated herein by reference to Exhibit 10.02(b) to Form 10-K (#001-3551) for the year ended December 31, 2012 |
| | | | 2012. |
| | Form of Participant Award Agreement (Stock Option) under 2009 Long-Term Incentive Plan (2013 grants). | | Incorporated herein by reference to Exhibit 10.02(t) to Form 10-K (#001-3551) for the year ended December 31, 2012 |
| | | | 2012. |
| | Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2009 Long-Term Incentive Plan (2013 and 2014 grants). | | Incorporated herein by reference to Exhibit 10.02(s) to Form 10-K (#001-3551) for the year ended December 31, 2012 |
| | | | |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
|
| | | | |
Exhibits | | Description | | Method of Filing |
| | | | |
| | | | 2012. |
| | Form of Participant Award Agreement (Stock Option) under 2009 Long-Term Incentive Plan (2014 grants). | | Incorporated herein by reference to Exhibit 10.02(v) to Form 10-K (#001-3551) for the year ended December 31, 2013 |
| | | | 2013. |
| EQT Corporation 2014 Long-Term Incentive Plan. | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on May 1, 2014. |
| Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2014 ExecutiveLong-Term Incentive Plan. | Incorporated herein by reference to Exhibit 10.03(b) to Form 10-K (#001-3551) for the year ended December 31, 2014. |
| Form of Restricted Stock Unit Award Agreement (Standard) under 2014 Long-Term Incentive Plan. | Incorporated herein by reference to Exhibit 10.02(o) to Form 10-K (#001-3551) for the year ended December 31, 2018. |
| Form of 2018 Value Driver Performance Award Agreement. | Incorporated herein by reference to Exhibit 10.02(s) to Form 10-K (#001-3551) for the year ended December 31, 2018. |
| Form of 2018 Restricted Stock Units Award Agreement (Standard) under 2014 Long-Term Incentive ProgramPlan (2018 grants). | Incorporated herein by reference to Exhibit 10.02(t) to Form 10-K (#001-3551) for the year ended December 31, 2018. |
| 2018 Incentive Performance Share Unit Program. | Incorporated herein by reference to Exhibit 10.02(t) to Form 10-K (#001-3551) for the year ended December 31, 2017. |
| Form of Participant Award Agreement under 2018 Incentive Performance Share Unit Program (executive officers). | Incorporated herein by reference to Exhibit 10.02(u) to Form 10-K (#001-3551) for the year ended December 31, 2017. |
| Form of Participant Award Agreement under 2018 Incentive Performance Share Unit Program. | Incorporated herein by reference to Exhibit 10.02(w) to Form 10-K (#001-3551) for the year ended December 31, 2013 |
| | | | 2018. |
| | Form of Participant2018 Restricted Stock Unit Award Agreement under 2014 Executive Performance Incentive Program(Transaction). | | Incorporated herein by reference to Exhibit 10.02(x)10.02(y) to Form 10-K (#001-3551) for the year ended December 31, 2013 |
| | | | 2018. |
| | Form of Participant Award Agreement (Stock Option) under 2014 Long-Term Incentive Plan (2019 grants). | Incorporated herein by reference to Exhibit 10.02(z) to Form 10-K (#001-3551) for the year ended December 31, 2018. |
| Form of Restricted Stock Award Agreement (Standard) under 2014 Long-Term Incentive Plan (2019 grants). | Incorporated herein by reference to Exhibit 10.02(aa) to Form 10-K (#001-3551) for the year ended December 31, 2018. |
| 2019 Incentive Performance Share Unit Program. | Incorporated herein by reference to Exhibit 10.02(bb) to Form 10-K (#001-3551) for the year ended December 31, 2018. |
| Form of Participant Award Agreement under 2019 Incentive Performance Share Unit Program. | Incorporated herein by reference to Exhibit 10.02(cc) to Form 10-K (#001-3551) for the year ended December 31, 2018. |
| Rice Energy Inc. 2014 Long-Term Incentive Plan (as amended and restated May 9, 2014). | Incorporated herein by reference to Exhibit 10.3 to Rice Energy Inc.'s Form 10-Q (#001-36273) for the quarter ended June 30, 2014. |
| EQT Corporation 2019 Long-Term Incentive Plan. | Incorporated herein by reference to Exhibit 99.1 to Form S-8 (#001-3551) filed on July 15, 2019. |
| Form of Restricted Stock Unit Award Agreement (Standard) under 2019 Long-Term Incentive Plan. | Incorporated herein by reference to Exhibit 10.06(c) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| | | | | | | | |
| Form of Incentive Performance Share Unit Program under 2019 Long-Term Incentive Plan. | Incorporated herein by reference to Exhibit 10.06(d) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Form of Participant Award Agreement under 2020 Incentive Performance Share Unit Program. | Incorporated herein by reference to Exhibit 10.06(e) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Form of Stock Appreciation Rights Award Agreement under 2019 Long-Term Incentive Plan. | Incorporated herein by reference to Exhibit 10.06(f) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| EQT Corporation 2020 Long-Term Incentive Plan. | Incorporated herein by reference to Exhibit 99.1 to Form S-8 (#333-237953) filed on May 1, 2020. |
| Form of Restricted Stock Unit Award Agreement (Standard). | Filed herewith as 10.10(a). |
| Form of Restricted Stock Unit Award Agreement (Non-Employee Directors). | Incorporated herein by reference to Exhibit 10.06(b) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Form of EQT Corporation Short-Term Incentive Plan. | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on May 1, 2014 |
| | | | 4, 2020. |
| Form of Incentive Performance Share Unit Program. | Filed herewith as 10.12(a). |
| Form of Participant Award Agreement under Incentive Performance Share Unit Program. | Filed herewith as 10.12(b). |
| Form of Participant Award Agreement (Stock Option). | Incorporated herein by reference to Exhibit 10.06(g) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| EQT Corporation Executive Severance Plan and Form of Participation Notice. | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on May 20, 2020. |
| EQT Corporation Employee Savings Plan. | Incorporated herein by reference to Exhibit 4.1 to Form S-8 (#333-230970) filed on April 22, 2019. |
| Form of Restricted Stock Unit Agreement (Directors) for Rice Energy Inc. | Incorporated herein by reference to Exhibit 10.19 to Rice Energy Inc.'s Amendment No. 2 to Form S-1 Registration Statement (#333-192894) filed on January 8, 2014. |
| 1999 Non-Employee Directors' Stock Incentive Plan (as amended and restated December 3, 2008). | Incorporated herein by reference to Exhibit 10.02(a) to Form 10-K (#001-3551) for the year ended December 31, 2008. |
| Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2014 Long-Term1999 Non-Employee Directors' Stock Incentive PlanPlan. | | Incorporated herein by reference to Exhibit 10.03(b)10.04(c) to Form 10-K (#001-3551) for the year ended December 31, 2014 |
| | | | 2006. |
| 1999 Directors' Deferred Compensation Plan (as amended and restated December 3, 2014). | 2015 Executive Performance Incentive Program | | Incorporated herein by reference to Exhibit 10.03(d)10.08 to Form 10-K (#001-3551) for the year ended December 31, 2014 |
| | | | 2014. |
| Amendment to 1999 Directors' Deferred Compensation Plan (as amended October 2, 2018). | Form of Participant Award Agreement under 2015 Executive Performance Incentive Program | | Incorporated herein by reference to Exhibit 10.03(e)10.4 to Form 10-Q (#001-3551) for the quarter ended September 30, 2018. |
| 2005 Directors' Deferred Compensation Plan (as amended and restated December 3, 2014). | Incorporated herein by reference to Exhibit 10.09 to Form 10-K (#001-3551) for the year ended December 31, 2014 |
| | | | 2014. |
| | Amendment to 2015 Executive Performance Incentive Program2005 Directors' Deferred Compensation Plan (as amended October 2, 2018). | | Incorporated herein by reference to Exhibit 10.03(f)10.5 to Form 10-Q (#001-3551) for the quarter ended September 30, 2018. |
| Form of Indemnification Agreement between EQT Corporation and executive officers and outside directors. | Incorporated herein by reference to Exhibit 10.18 to Form 10-K (#001-3551) for the year ended December 31, 2014 |
| | | | 2008. |
| Separation and Release Agreement, dated November 13, 2017, among EQT Corporation, EQT RE, LLC and Daniel J. Rice IV. | Form of EQT 2015 Value Driver Performance Award Agreement | | Incorporated herein by reference to Exhibit 10.9(c)10.1 to EQT Midstream Partners, LP's Form 10-K (#001-35574) for the year ended December 31, 20168-K (#001-3551) filed on November 17, 2017. |
| | | | | | | | |
| Offer Letter, dated January 13, 2020, between EQT Corporation and Kyle Derham. | 2016 Incentive Performance Share Unit Program | | Incorporated herein by reference to Exhibit 10.02(g)10.27(a) to Form 10-K (#001-3551) for the year ended December 31, 2015 |
| | | | 2019. |
| Services Agreement, dated January 13, 2020, between EQT Corporation and Kyle Derham. | Form of Participant Award Agreement under 2016 Incentive Performance Share Unit Program | | Incorporated herein by reference to Exhibit 10.02(h)10.27(b) to Form 10-K (#001-3551) for the year ended December 31, 20152019. |
| Offer Letter, dated December 18, 2019, between EQT Corporation and David M. Khani. | Incorporated herein by reference to Exhibit 10.28(a) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Confidentiality, Non-Solicitation and Non-Competition Agreement, dated January 3, 2020, between EQT Corporation and David M. Khani. | Incorporated herein by reference to Exhibit 10.28(b) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Offer Letter, dated January 6, 2020, between EQT Corporation and William E. Jordan. | Incorporated herein by reference to Exhibit 10.29(a) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Confidentiality, Non-Solicitation and Non-Competition Agreement, dated January 6, 2020, between EQT Corporation and William E. Jordan. | Incorporated herein by reference to Exhibit 10.29(b) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Offer Letter, dated July 18, 2019, between EQT Corporation and Richard Anthony Duran. | Incorporated herein by reference to Exhibit 10.30(a) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Confidentiality, Non-Solicitation and Non-Competition Agreement, dated August 5, 2019, between EQT Corporation and Richard Anthony Duran. | Incorporated herein by reference to Exhibit 10.30(b) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Relocation Expense Reimbursement Agreement, dated July 24, 2019, between EQT Corporation and Richard Anthony Duran. | Incorporated herein by reference to Exhibit 10.30(c) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Offer Letter, dated July 16, 2019, between EQT Corporation and Lesley Evancho. | Incorporated herein by reference to Exhibit 10.31(a) to Form 10-K (#001-3551) for the year ended December 31, 2019. |
| Schedule of Subsidiaries. | Filed herewith as Exhibit 21. |
| Consent of Independent Registered Public Accounting Firm. | Filed herewith as Exhibit 23.01. |
| Consent of Netherland, Sewell & Associates, Inc. | Filed herewith as Exhibit 23.02. |
| Rule 13(a)-14(a) Certification of Principal Executive Officer. | Filed herewith as Exhibit 31.01. |
| Rule 13(a)-14(a) Certification of Principal Financial Officer. | Filed herewith as Exhibit 31.02. |
| Section 1350 Certification of Principal Executive Officer and Principal Financial Officer. | Furnished herewith as Exhibit 32. |
| Independent Petroleum Engineers' Audit Report. | Filed herewith as Exhibit 99. |
| 101 | Interactive Data File. | Filed herewith as Exhibit 101. |
| 104 | Cover Page Interactive Data File. | Formatted as Inline XBRL and contained in Exhibit 101. |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
|
| | | | |
Exhibits | | Description | | Method of Filing |
| | | | |
| | 2016 Restricted Stock Award Agreement (Standard) for Robert J. McNally | | Incorporated herein by reference to Exhibit 10.03 to Form 10-Q (#001-3551) for the quarter ended March 31, 2016 |
| | | | |
| | Form of EQT 2016 Value Driver Performance Award Agreement | | Incorporated herein by reference to Exhibit 10.9(d) to EQT Midstream Partners, LP's Form 10-K (#001-35574) for the year ended December 31, 2016 |
| | | | |
| | Form of Participant Award Agreement (Stock Option) under 2014 Long-Term Incentive Plan (pre-2017 grants) | | Incorporated herein by reference to Exhibit 10.03(c) to Form 10-K (#001-3551) for the year ended December 31, 2014 |
| | | | |
| | 2017 Incentive Performance Share Unit Program | | Incorporated herein by reference to Exhibit 10.02(l) to Form 10-K (#001-3551) for the year ended December 31, 2016 |
| | | | |
| | Form of Participant Award Agreement under 2017 Incentive Performance Share Unit Program | | Incorporated herein by reference to Exhibit 10.02(m) to Form 10-K (#001-3551) for the year ended December 31, 2016 |
| | | | |
| | Form of Participant Award Agreement (Stock Option) under 2014 Long-Term Incentive Plan (2017 grants) | | Incorporated herein by reference to Exhibit 10.02(k) to Form 10-K (#001-3551) for the year ended December 31, 2016 |
| | | | |
| | Form of EQT 2017 Value Driver Performance Award Agreement | | Incorporated herein by reference to Exhibit 10.9(e) to EQT Midstream Partners, LP's Form 10-K (#001-35574) for the year ended December 31, 2016 |
| | | | |
| | Form of EQT Restricted Stock Unit Award Agreement (Standard) | | Incorporated herein by reference to Exhibit 10.9(a) to EQT Midstream Partners, LP's Form 10-K (#001-35574) for the year ended December 31, 2016 |
| | | | |
| | Form of Restricted Stock Award Agreement under 2014
Long-Term Incentive Plan (pre-2018 grants) | | Incorporated herein by reference to Exhibit 10.02(d) to Form 10-K (#001-3551) for the year ended December 31, 2016 |
| | | | |
| | Form of Participant Award Agreement (Stock Option) under 2014 Long-Term Incentive Plan (2018 grants) | | Filed herewith as Exhibit 10.02(r) |
| | | | |
| | Form of Restricted Stock Award Agreement under 2014 Long-Term Incentive Plan (2018 grants) | | Filed herewith as Exhibit 10.02(s) |
| | | | |
| | 2018 Incentive Performance Share Unit Program | | Filed herewith as Exhibit 10.02(t) |
| | | | |
| | Form of Participant Award Agreement under 2018 Incentive Performance Share Unit Program | | Filed herewith as Exhibit 10.02(u) |
| | | | |
| | Rice Energy Inc. 2014 Long-Term Incentive Plan (as amended and restated May 9, 2014) | | Incorporated herein by reference to Exhibit 10.3 to Rice Energy Inc.'s Form 10-Q (#001-36273) for the quarter ended June 30, 2014 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
|
| | | | |
Exhibits | | Description | | Method of Filing |
| | | | |
| | Form of Restricted Stock Unit Agreement (Directors) for Rice Energy Inc. | | Incorporated herein by reference to Exhibit 10.19 to Rice Energy Inc.'s Amendment No. 2 to Form S-1 Registration Statement (#333-192894) filed on January 8, 2014 |
| | | | |
| | EQT GP Services, LLC 2015 Long-Term Incentive Plan | | Incorporated herein by reference to Exhibit 10.3 to EQT GP Holdings, LP's Form 8-K (#001-37380) filed on May 15, 2015 |
| | | | |
| | Form of EQT GP Holdings, LP Phantom Unit Award Agreement | | Incorporated herein by reference to Exhibit 10.5 to EQT GP Holdings, LP's Amendment No. 1 to Form S-1 Registration Statement (#333-202053) filed on April 1, 2015 |
| | | | |
| | EQT Midstream Services, LLC 2012 Long-Term Incentive Plan | | Incorporated herein by reference to Exhibit 10.03 to Form 10-K (#001-3551) for the year ended December 31, 2012 |
| | | | |
| | Rice Midstream Partners LP 2014 Long-Term Incentive Plan | | Incorporated herein by reference to Exhibit 4.3 to Rice Midstream Partners LP's Form S-8 Registration Statement (#333-201169) filed on December 19, 2014 |
| | | | |
| | 1999 Non-Employee Directors’ Stock Incentive Plan (as amended and restated December 3, 2008) | | Incorporated herein by reference to Exhibit 10.02(a) to Form 10-K (#001-3551) for the year ended December 31, 2008 |
| | | | |
| | Form of Participant Award Agreement (Phantom Stock Unit Awards) under 1999 Non-Employee Directors’ Stock Incentive Plan | | Incorporated herein by reference to Exhibit 10.04(c) to Form 10-K (#001-3551) for the year ended December 31, 2006 |
| | | | |
| | 2016 Executive Short-Term Incentive Plan | | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on April 21, 2016 |
| | | | |
| | 2006 Payroll Deduction and Contribution Program (as amended and restated July 7, 2015) | | Incorporated herein by reference to Exhibit 10.06 to Form 10-Q (#001-3551) for the quarter ended June 30, 2015 |
| | | | |
| | 1999 Directors' Deferred Compensation Plan (as amended and restated December 3, 2014) | | Incorporated herein by reference to Exhibit 10.08 to Form 10-K (#001-3551) for the year ended December 31, 2014 |
| | | | |
| | 2005 Directors’ Deferred Compensation Plan (as amended and restated December 3, 2014) | | Incorporated herein by reference to Exhibit 10.09 to Form 10-K (#001-3551) for the year ended December 31, 2014 |
| | | | |
| | Form of Indemnification Agreement between the Company and each executive officer and each outside director | | Incorporated herein by reference to Exhibit 10.18 to Form 10-K (#001-3551) for the year ended December 31, 2008 |
| | | | |
| | Second Amended and Restated Credit Agreement dated as of July 31, 2017 among the Company, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer and the other lenders party thereto | | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on August 3, 2017 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
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| | | | |
Exhibits | | Description | | Method of Filing |
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| | Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and David L. Porges | | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on July 31, 2015 |
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| | Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and Steven T. Schlotterbeck | | Incorporated herein by reference to Exhibit 10.5 to Form 8-K (#001-3551) filed on July 31, 2015 |
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| | Offer letter dated as of March 7, 2016 between the Company and Robert J. McNally | | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on March 17, 2016 |
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| | Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of March 10, 2016 between the Company and Robert J. McNally | | Incorporated herein by reference to Exhibit 10.02 to Form 10-Q (#001-3551) for the quarter ended March 31, 2016 |
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| | Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and Lewis B. Gardner | | Incorporated herein by reference to Exhibit 10.4 to Form 8-K (#001-3551) filed on July 31, 2015 |
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| | Second Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of March 1, 2017 between the Company and David E. Schlosser, Jr. | | Filed herewith as Exhibit 10.17 |
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| | Offer Letter dated as of July 26, 2017 between the Company and Jeremiah J. Ashcroft III | | Filed herewith as Exhibit 10.18(a) |
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| | Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of August 7, 2017 between the Company and Jeremiah J. Ashcroft III | | Filed herewith as Exhibit 10.18(b) |
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| | Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and M. Elise Hyland | | Incorporated herein by reference to Exhibit 10.2 to EQT Midstream Partners, LP's Form 10-Q (#001-35574) for the quarter ended March 31, 2017 |
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| | Transition Agreement and General Release dated as of February 28, 2017 between the Company and M. Elise Hyland | | Incorporated herein by reference to Exhibit 10.3 to EQT Midstream Partners, LP's Form 10-Q (#001-35574) for the quarter ended March 31, 2017 |
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| | Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and Randall L. Crawford | | Incorporated herein by reference to Exhibit 10.3 to Form 8-K (#001-3551) filed on July 31, 2015 |
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| | Amendment to Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement effective as of January 1, 2016 between the Company and Randall L. Crawford | | Incorporated herein by reference to Exhibit 10.12(b) to Form 10-K (#001-3551) for the year ended December 31, 2015 |
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| | Transition Agreement and General Release dated as of January 9, 2017 between the Company and Randall L. Crawford | | Incorporated herein by reference to Exhibit 10.14(e) to Form 10-K (#001-3551) for the year ended December 31, 2016 |
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| | Separation and Release Agreement, dated as of November 13, 2017, among the Company, EQT RE, LLC and Daniel J. Rice IV | | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on November 17, 2017 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
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Exhibits | | Description | | Method of Filing |
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| | Schedule of Subsidiaries | | Filed herewith as Exhibit 21 |
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| | Consent of Independent Registered Public Accounting Firm | | Filed herewith as Exhibit 23.01 |
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| | Consent of Ryder Scott Company, L.P. | | Filed herewith as Exhibit 23.02 |
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| | Rule 13(a)-14(a) Certification of Principal Executive Officer | | Filed herewith as Exhibit 31.01 |
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| | Rule 13(a)-14(a) Certification of Principal Financial Officer | | Filed herewith as Exhibit 31.02 |
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| | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer | | Furnished herewith as Exhibit 32 |
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| | Independent Petroleum Engineers’ Audit Report | | Filed herewith as Exhibit 99 |
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101 | | Interactive Data File | | Filed herewith as Exhibit 101 |
The Company agreesWe agree to furnish to the SEC, upon request, copies of instruments with respect to long-term debt whichthat have not previously been filed.
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
Item 16.Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | EQT CORPORATION |
| | |
| | By: | /s/ STEVEN T. SCHLOTTERBECKToby Z. Rice |
| | | Steven T. SchlotterbeckToby Z. Rice |
| | | President and Chief Executive Officer |
| | | February 15, 201817, 2021 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| | | | | | | | | | | | | | |
| /s/ TOBY Z. RICE | | President, | | February 17, 2021 |
| Toby Z. Rice | | Chief Executive Officer and | | |
| (Principal Executive Officer) | | Director | | |
| | | | |
| /s/ DAVID M. KHANI | | Chief Financial Officer | | February 17, 2021 |
| David M. Khani | | | | |
| (Principal Financial Officer) | | | | |
| | | | |
| /s/ TODD M. JAMES | | Chief Accounting Officer | | February 17, 2021 |
| Todd M. James | | | | |
| (Principal Accounting Officer) | | | | |
| | | | |
| /s/ LYDIA I. BEEBE | | Chair | | February 17, 2021 |
| Lydia I. Beebe | | | | |
| | | | |
| /s/ PHILIP G. BEHRMAN | | Director | | February 17, 2021 |
| Philip G. Behrman | | | | |
| | | | |
/s/ STEVEN T. SCHLOTTERBECKLEE M. CANAAN | | President,Director | | February 15, 201817, 2021 |
Steven T. SchlotterbeckLee M. Canaan | | Chief Executive Officer and | | |
(Principal Executive Officer) | | Director | | |
| /s/ JANET L. CARRIG | | Director | | February 17, 2021 |
/s/ ROBERT J. MCNALLY Janet L. Carrig | | Senior Vice President | | February 15, 2018 |
Robert J. McNally | | and Chief Financial Officer | | |
(Principal Financial Officer)/s/ KATHRYN J. JACKSON | | Director | | February 17, 2021 |
| Kathryn J. Jackson | | | | |
/s/ JIMMI SUE SMITH | | Chief Accounting Officer | | February 15, 2018 |
Jimmi Sue Smith/s/ JOHN F. MCCARTNEY | | Director | | February 17, 2021 |
(Principal Accounting Officer)John F. McCartney | | | | |
| | | | |
/s/ VICKY A. BAILEY JAMES T. MCMANUS II | | Director | | February 15, 201817, 2021 |
Vicky A. BaileyJames T. McManus II | | | | |
| | | | |
/s/ PHILIP G. BEHRMAN ANITA M. POWERS | | Director | | February 15, 201817, 2021 |
Philip G. BehrmanAnita M. Powers | | | | |
| | | | |
/s/ KENNETH M. BURKE | | Director | | February 15, 2018 |
Kenneth M. Burke | | | | |
| | | | |
/s/ A. BRAY CARY JR. | | Director | | February 15, 2018 |
A. Bray Cary, Jr. | | | | |
| | | | |
/s/ MARGARET K. DORMAN | | Director | | February 15, 2018 |
Margaret K. Dorman | | | | |
| | | | |
/s/ THOMAS F. KARAM | | Director | | February 15, 2018 |
Thomas F. Karam | | | | |
| | | | |
/s/ DAVID L. PORGES | | Executive Chairman | | February 15, 2018 |
David L. Porges | | | | |
| | | | |
| /s/ DANIEL J. RICE IV | | Director | | February 15, 201817, 2021 |
| Daniel J. Rice IV | | | | |
| | | | |
/s/ JAMES E. ROHR | | Director | | February 15, 2018 |
James E. Rohr | | | | |
| | | | |
/s/ NORMAN J. SZYDLOWSKI | | Director | | February 15, 2018 |
Norman J. Szydlowski | | | | |
| | | | |
| /s/ STEPHEN A. THORINGTON | | Director | | February 15, 201817, 2021 |
| Stephen A. Thorington | | | | |
| | | | |
/s/ LEE T. TODD, JR. HALLIE A. VANDERHIDER | | Director | | February 15, 201817, 2021 |
Lee T. Todd, Jr.Hallie A. Vanderhider | | | | |
| | | | |
/s/ CHRISTINE J. TORETTI | | Director | | February 15, 2018 |
Christine J. Toretti | | | | |
| | | | |
/s/ ROBERT F. VAGT | | Director | | February 15, 2018 |
Robert F. Vagt | | | | |
